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As filed with the Securities and Exchange Commission on June 21, 2004
Registration No. 333-113588



UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


AMENDMENT NO. 3 TO

Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933


Holly Energy Partners, L.P.

(Exact name of Registrant as Specified in Its Charter)


         
Delaware   4610   20-0833098
(State or Other Jurisdiction of
Incorporation or Organization)
  (Primary Standard Industrial
Classification Code Number)
  (I.R.S. Employer
Identification Number)

100 Crescent Court, Suite 1600

Dallas, Texas 75201
(214) 871-3555
(Address, Including Zip Code, and Telephone Number, including
Area Code, of Registrant’s Principal Executive Offices)

Matthew P. Clifton

100 Crescent Court, Suite 1600
Dallas, Texas 75201
(214) 871-3555
(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)


Copies to:

     
Alan J. Bogdanow
Vinson & Elkins L.L.P.
3700 Trammell Crow Center
2001 Ross Avenue
Dallas, Texas 75201-2975
(214) 220-7700
  Joshua Davidson
Baker Botts L.L.P.
910 Louisiana
Houston, Texas 77002
(713) 229-1234


      Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.


      If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.    o

      If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

      If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

      If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

      If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box.    o


      The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.




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The information in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell nor does it seek an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

Subject to Completion. Dated June 21, 2004.

6,000,000 Common Units

(HOLLY ENERGY PARTNERS LOGO)

Representing Limited Partner Interests


       This is an initial public offering of common units representing limited partner interests of Holly Energy Partners, L.P. Holly Energy Partners intends to distribute to each common unit the minimum quarterly distribution of $0.50 per quarter or $2.00 per year, to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses to its general partner. The common units are entitled to receive the minimum quarterly distribution before any distribution is paid on the subordinated units initially held by affiliates of Holly Corporation.

       Prior to this offering, there has been no public market for the common units. It is currently estimated that the initial public offering price per common unit will be between $20.25 and $22.25. The common units have been approved for listing on the New York Stock Exchange under the symbol “HEP.”

       See “Risk Factors” on page 16 to read about important factors that you should consider before buying common units.

       These risks include the following:

  •  We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.
 
  •  We depend upon Holly Corporation and particularly its Navajo Refinery for a substantial majority of our revenues, and any reduction in these revenues would reduce our ability to make distributions to unitholders.
 
  •  Competition from other pipelines could cause us to reduce our rates or could reduce our revenues.
 
  •  A material decrease in the supply, or a material increase in the price, of crude oil available to Holly Corporation’s refineries could materially reduce our ability to make distributions to unitholders.
 
  •  Our operations are subject to federal, state, and local laws and regulations relating to environmental protection and operational safety that could require us to make substantial expenditures.
 
  •  Holly Corporation and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to your detriment.
 
  •  Even if unitholders are dissatisfied, they cannot remove our general partner without its consent.
 
  •  The control of our general partner may be transferred to a third party without unitholder consent.
 
  •  You will experience immediate and substantial dilution of $16.94 per common unit.
 
  •  You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.


       Neither the Securities and Exchange Commission nor any other regulatory body has approved or disapproved of these securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.


             
Per
Common Unit Total


Initial public offering price
  $   $    
Underwriting discount(1)
  $   $    
Proceeds before expenses, to Holly Energy Partners, L.P.
  $   $    


(1)  Excludes structuring fees of $        to be paid to Goldman, Sachs & Co.

       To the extent that the underwriters sell more than 6,000,000 common units, the underwriters have the option to purchase up to an additional 900,000 common units from Holly Energy Partners at the initial public offering price less the underwriting discount.


       The underwriters expect to deliver the common units against payment in New York, New York on                 , 2004.

Goldman, Sachs & Co.

  Lehman Brothers
  UBS Investment Bank
  A.G. Edwards
  Raymond James


Prospectus dated                 , 2004.


Table of Contents

(MAP OF HOLLY ENERGY PARTNERS’ PIPELINES AND TERMINALS)


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    F-1  
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 Form of 1st Amended & Restated Agreement-Operating
 Form of 1st Amended & Restated Agreement-Logistic
 Pipeline Lease Agreement
 Transporation Agreement
 Consent of Ernst & Young LLP
 Consent of Ernst & Young LLP


       You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus.

       Through and including                     , 2004 (the 25th day after the date of this prospectus), all dealers effecting transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

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SUMMARY

       This summary highlights information contained elsewhere in this prospectus. It does not contain all of the information that you should consider before investing in the common units. You should read the entire prospectus carefully, including the historical and pro forma financial statements and notes to those financial statements. The information presented in this prospectus assumes (1) an initial public offering price of $21.25 per unit and (2) that the underwriters’ over-allotment option is not exercised. You should read “Risk Factors” beginning on page 16 for more information about important factors that you should consider before buying the common units.

       We include a glossary of some of the terms used in this prospectus as Appendix C. References in this prospectus to “Holly Energy Partners,” “we,” “our,” “us,” or like terms refer to Holly Energy Partners, L.P.

Holly Energy Partners

       Holly Energy Partners is a Delaware limited partnership recently formed by Holly Corporation. We operate a system of refined product pipelines and distribution terminals primarily in West Texas, New Mexico, Utah and Arizona. We generate revenues by charging tariffs for transporting refined products through our pipelines and by charging fees for terminalling refined products and other hydrocarbons in, and storing and providing other services at, our terminals. We do not take ownership of products that we transport or terminal and therefore we are not directly exposed to changes in commodity prices. We serve Holly Corporation’s refineries in New Mexico and Utah under a 15 year pipelines and terminals agreement. We are dedicated to generating stable cash flows and growing our business. Our assets include:

  •  Refined Product Pipelines:

  •  approximately 780 miles of refined product pipelines, including 340 miles of leased pipelines, that transport gasoline, diesel, and jet fuel from Holly Corporation’s Navajo Refinery in New Mexico to its customers in the metropolitan and rural areas of Texas, New Mexico, Arizona, Colorado, Utah and northern Mexico; and
 
  •  a 70% interest in the Rio Grande Pipeline Company, a joint venture that owns a 249-mile refined product pipeline, that transports liquid petroleum gases, or LPGs, from West Texas to the Texas/ Mexico border near El Paso for further transport into northern Mexico.

  •  Refined Product Terminals:

  •  five refined product terminals (two of which are 50% owned), located in El Paso, Texas; Moriarty, Bloomfield and Albuquerque, New Mexico; and Tucson, Arizona, with an aggregate capacity of approximately 1.1 million barrels, that are integrated with our refined product pipeline system;
 
  •  three refined product terminals (two of which are 50% owned), located in Burley and Boise, Idaho and Spokane, Washington, with an aggregate capacity of approximately 514,000 barrels, that serve third party common carrier pipelines;
 
  •  one refined product terminal near Mountain Home, Idaho with a capacity of 120,000 barrels, that serves a nearby United States Air Force Base; and
 
  •  two refined product truck loading racks, one located within Holly Corporation’s Navajo Refinery, that is permitted to load over 40,000 barrels per day (bpd) of light refined products, and one located within Holly Corporation’s Woods Cross Refinery near Salt Lake City, Utah, that is permitted to load over 25,000 bpd of light refined products.

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       In addition, we have an option to purchase two intermediate product pipelines from Holly Corporation at fair market value. These pipelines transport crude oil and feedstocks from Holly Corporation’s Lovington facility to its Artesia facility. These pipelines are each 65 miles long and have a current aggregate throughput capacity of 84,000 bpd.

       For the year ended December 31, 2003, on a pro forma basis, reflecting the tariff and terminal fees we will initially charge Holly Corporation under the pipelines and terminals agreement, we had revenues of approximately $52.7 million, net income of approximately $21.4 million and earnings before interest, taxes, depreciation and amortization, or EBITDA, of approximately $29.8 million. For the three months ended March 31, 2004, on a pro forma basis, we had revenues of $15.4 million, net income of approximately $7.3 million and EBITDA of approximately $9.5 million. Please read “Summary Historical and Operating Data and Pro Forma Financial Data” for an explanation of the term EBITDA and a reconciliation of EBITDA to net income and cash flow from operating activities, our most directly comparable financial measures, calculated and presented in accordance with GAAP. For the year ended December 31, 2003, on a pro forma basis, pipelines accounted for approximately 81.2% of our revenues and terminals accounted for approximately 18.8% of our revenues. For the three months ended March 31, 2004, on a pro forma basis, pipelines accounted for approximately 80.2% of our revenues and terminals accounted for approximately 19.8% of our revenues.

Our Relationship with Holly Corporation

       The substantial majority of our business is devoted to providing transportation and terminalling services to Holly Corporation. For the year ended December 31, 2003, Holly Corporation accounted for approximately $30.2 million, or 57.3%, of our pro forma revenues. For the three months ended March 31, 2004, Holly Corporation accounted for approximately $9.2 million, or 59.6%, of our pro forma revenues. We expect to continue to derive a substantial majority of our revenues from Holly Corporation for the foreseeable future.

       Holly Corporation owns and operates the Navajo Refinery, the largest refinery in New Mexico, consisting of refining facilities that are located 65 miles apart in Artesia and Lovington and operated in conjunction with each other. Having recently completed a 15,000 bpd expansion, the Navajo Refinery currently has a crude oil processing capacity of 75,000 bpd. The majority of our operations are located within Holly Corporation’s New Mexico refining market area. Holly Corporation relies on us to provide almost all of the light refined product transportation and terminalling services it requires to support its New Mexico refining operations. For the year ended December 31, 2003 and the three months ended March 31, 2004, we transported and terminalled approximately 99% of the light refined products produced by the Navajo Refinery. In addition, we provide terminalling services for Holly Corporation’s Woods Cross Refinery near Salt Lake City, Utah. Since June 1, 2003, the date Holly Corporation acquired the Woods Cross Refinery, through March 31, 2004, we terminalled 100% of the light refined products produced by the Woods Cross Refinery. Holly Corporation also operates a refinery in Great Falls, Montana. We have no operations relating to the Montana Refinery.

       Concurrently with the closing of this offering, we will enter into a 15 year pipelines and terminals agreement with Holly Corporation. Under this agreement, Holly Corporation will pay us fees that we believe are comparable to those that would be charged by third parties. Holly Corporation will also agree to transport on our refined product pipelines and throughput in our terminals a volume of refined products that will result in minimum revenues of $35.4 million in the first year. This minimum revenue commitment will increase each year at a rate equal to the percentage change in the producer price index, but will not decrease as a result of a decrease in the producer price index. Holly Corporation’s obligations under this agreement may be proportionately reduced or suspended if Holly Corporation decides to shut down or materially reconfigure one of its refineries. Holly Corporation’s obligations may also be temporarily

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suspended under certain circumstances. Holly Corporation will be required to give at least twelve months’ advance notice of any long-term shut-down or material reconfiguration. Please read “Business — Our Relationship with Holly Corporation — Pipelines and Terminals Agreement.”

       We will also enter into an omnibus agreement with Holly Corporation and its affiliates under which they will generally agree not to engage in the business of operating refined product pipelines or terminals, intermediate pipelines or terminals, crude oil pipelines or terminals, truck racks or crude oil gathering systems in the continental United States. In addition, this agreement addresses our payment of a fee to Holly Corporation for the provision of various general and administrative services, Holly Corporation’s indemnification of us for certain environmental and other liabilities, and other matters. Please read “Certain Relationships and Related Party Transactions — Omnibus Agreement.”

       Holly Corporation’s common stock trades on the New York Stock Exchange under the symbol “HOC.” For the year ended December 31, 2003 and the three months ended March 31, 2004, Holly Corporation had revenues of $1.4 billion and $463 million, respectively, and net income of $46.1 million and $14.0 million, respectively. Holly Corporation is subject to the information requirements of the Securities Exchange Act of 1934. Please read “Where You Can Find More Information.”

Summary of Risk Factors

       An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of our common units. Those risks are described under the caption “Risk Factors” beginning on page 16 and include:

Risks Inherent in Our Business

  •  We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.
 
  •  We depend upon Holly Corporation and particularly its Navajo Refinery for a substantial majority of our revenues and if those revenues were reduced, there would be a material adverse effect on our results of operations and our ability to make distributions to unitholders.
 
  •  Competition from other pipelines that may be able to supply Holly Corporation’s customers with refined products at a lower price, including the Longhorn Pipeline, which may become operational late in the summer of 2004, could cause us to reduce our rates or could reduce our revenues.
 
  •  A material decrease in the supply, or a material increase in the price, of crude oil available to Holly Corporation’s refineries, could materially reduce our ability to make distributions to unitholders.
 
  •  We are exposed to the credit risks of our key customers, including Holly Corporation, and any material nonpayment or nonperformance by our key customers could reduce our ability to make distributions to our unitholders.
 
  •  Due to our lack of asset diversification, adverse developments in our pipelines and terminals business would reduce our ability to make distributions to our unitholders.
 
  •  Our operations are subject to federal, state, and local laws and regulations relating to environmental protection and operational safety that could require us to make substantial expenditures.
 
  •  Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

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  •  If our assumptions concerning population growth are inaccurate or if Holly Corporation’s growth strategy is not successful, our ability to make or increase distributions to unitholders may be adversely affected.
 
  •  Restrictions in our credit agreement may prevent us from engaging in some beneficial transactions or paying distributions.
 
  •  Rate regulation may not allow us to recover the full amount of increases in our costs.
 
  •  Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.
 
  •  An adverse decision in a lawsuit pending between Holly Corporation and Frontier Oil Corporation could have a material adverse effect on Holly Corporation’s financial condition and therefore on our results of operations.

Risks Inherent in an Investment in Us

  •  Holly Corporation and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to your detriment.
 
  •  Cost reimbursements, which will be determined by our general partner, and fees due our general partner and its affiliates for services provided will be substantial and will reduce our cash available for distribution to you.
 
  •  Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
 
  •  Even if unitholders are dissatisfied, they cannot remove our general partner without its consent.
 
  •  The control of our general partner may be transferred to a third party without unitholder consent.
 
  •  You will experience immediate and substantial dilution of $16.94 per common unit.
 
  •  We may issue additional common units without your approval, which would dilute your ownership interests.
 
  •  In establishing cash reserves, our general partner may reduce the amount of cash available for distribution to you.

Tax Risks

  •  Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by states. If the IRS were to treat us as a corporation or if we were to become subject to entity-level taxation for state tax purposes, then our cash available for distribution to you would be substantially reduced.
 
  •  A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units, and the costs of any contest will be borne by our unitholders and our general partner.
 
  •  You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.
 
  •  We will register as a tax shelter. This may increase the risk of an IRS audit of us or a unitholder.

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Business Strategies

       Our primary business objective is to increase distributable cash flow per unit by executing the following strategies:

  •  Generate stable cash flows through the use of long-term contracts, including the pipelines and terminals agreement we will enter into with Holly Corporation at the closing of this offering.
 
  •  Increase our pipeline and terminal throughput by focusing on markets with increasing demand for light refined products.
 
  •  Undertake economic construction and expansion opportunities in specific markets to meet rising demand for light refined products in the Southwestern United States, northern Mexico and the Rocky Mountain region of the United States.
 
  •  Pursue strategic and accretive acquisitions that complement our existing asset base.

Competitive Strengths

       We believe we are well-positioned to execute our business strategies successfully using the following competitive strengths:

  •  Substantially all of our assets are located in markets with above average population growth, which we expect will result in increased demand for light refined products.
 
  •  We will operate a substantial part of our business under long-term contracts which we believe will enhance the stability and predictability of our cash flows.
 
  •  Our assets are modern, efficient, and well maintained.
 
  •  We have a strategic relationship with Holly Corporation. Substantially all of our refined product pipelines are linked to Holly Corporation’s refineries and provide Holly Corporation with the safest and most cost-effective means to distribute its light refined products.
 
  •  We are contractually and strategically positioned to benefit from Holly Corporation’s growth initiatives due to the strategic links between our assets and Holly Corporation’s refineries.
 
  •  We will have the financial flexibility to pursue expansion and acquisition opportunities due to a $100.0 million credit agreement we expect to enter into following the closing of this offering.
 
  •  We have an experienced management team.

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The Transactions

General

       We have recently been formed as a Delaware limited partnership to own and operate the refined product pipelines and distribution terminals currently owned or leased by Holly Corporation and its subsidiaries. Holly Corporation and its subsidiaries have agreed to contribute certain of their assets and liabilities to us or our subsidiaries in exchange for an aggregate of 1,000,000 common units and 7,000,000 subordinated units representing limited partner interests in us, a 2% general partner interest in us, and all of our incentive distribution rights, which entitle the general partner to increasing percentages of the cash we distribute in excess of $0.55 per unit per quarter.

       At the closing of this offering, the following transactions will occur:

  •  We will issue 6,000,000 common units to the public in this offering, representing a 42% limited partner interest in us, and will use the net proceeds to repay debt, make a cash distribution to Holly Corporation and to fund our working capital needs.
 
  •  We will enter into a new $100.0 million credit agreement. We will borrow $25.0 million under the credit agreement to fund an additional cash distribution to Holly Corporation.
 
  •  Holly Corporation will enter into the pipelines and terminals agreement with us.
 
  •  Holly Corporation will agree not to compete with us in some respects and to indemnify us for certain pre-closing liabilities pursuant to the omnibus agreement.

       References in this prospectus to “Holly Energy Partners,” “we,” “our,” “us” or like terms when used in a historical context refer to the assets of Holly Corporation and its subsidiaries that are being contributed to Holly Energy Partners, L.P. and its subsidiaries in connection with the offering. When used in the present tense or prospectively, those terms refer to Holly Energy Partners, L.P.

Holding Company Structure

       As is common with publicly traded limited partnerships and in order to maximize operational flexibility, we will conduct our operations through subsidiaries. We will have two direct subsidiaries initially: HEP Operating Company, L.P., a limited partnership that will conduct all of our operations through itself and its subsidiaries, and HEP Logistics GP, L.L.C., its general partner. HEP Operating Company, L.P. will own 100% of the membership interests in its subsidiaries, other than Rio Grande Pipeline Company, in which it will indirectly own a 70% interest.

Organizational Structure After the Transactions

       The following diagram depicts our organizational structure after giving effect to the transactions.

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Organizational Structure After the Transactions

(HOLLY ENERGY CHART)

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Management of Holly Energy Partners, L.P.

       Holly Logistic Services, L.L.C., as the general partner of HEP Logistics Holdings, L.P., our general partner, will manage our operations and activities. The executive officers and directors of Holly Logistic Services, L.L.C. currently serve as executive officers and directors of Holly Corporation. For more information about these individuals, please read “Management — Directors and Executive Officers of Holly Logistic Services, L.L.C.”

       Neither our general partner nor the board of directors of Holly Logistic Services, L.L.C. will be elected by our unitholders. Unlike shareholders in a publicly traded corporation, our unitholders will not be entitled to elect the directors of Holly Logistic Services, L.L.C.

       Holly Corporation will receive an annual administrative fee, initially in the amount of $2.0 million, for the provision of various general and administrative services for our benefit. The administrative fee may increase in the second and third years by the greater of 5% or the percentage increase in the consumer price index and may also increase if we make an acquisition that requires an increase in the level of general and administrative services that we receive from Holly Corporation or its affiliates. The $2.0 million fee does not include salaries of pipeline and terminal personnel or other employees of Holly Logistic Services, L.L.C. or the cost of their employee benefits, all of which are a component of our direct operating costs. We will also reimburse Holly Corporation and its affiliates for direct expenses they incur on our behalf. We also anticipate incurring approximately $1.7 million in additional general and administrative costs, including costs related to operating as a separate publicly held entity. Please read “Certain Relationships and Related Party Transactions.”

       Our principal executive offices are located at 100 Crescent Court, Suite 1600, Dallas, Texas 75201, and our telephone number is (214) 871-3555. Our website is located at www.hollyenergy.com. We expect to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Summary of Conflicts of Interest and Fiduciary Duties

       HEP Logistics Holdings, L.P., our general partner, has a legal duty to manage us in a manner beneficial to our unitholders. This legal duty originates in statutes and judicial decisions and is commonly referred to as a “fiduciary duty.” However, because Holly Logistic Services, L.L.C., the general partner of our general partner, is indirectly wholly owned by Holly Corporation, the officers and directors of Holly Logistic Services, L.L.C. have fiduciary duties to manage the business of Holly Logistic Services, L.L.C. in a manner beneficial to Holly Corporation. As a result of this relationship, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, on the other hand. For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties.”

       Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions that might otherwise constitute breaches of our general partner’s fiduciary duty. By purchasing a common unit, you are treated as having consented to various actions contemplated in the partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under applicable state law.

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The Offering

 
Common units offered to
the public
6,000,000 common units.
 
6,900,000 common units if the underwriters exercise their over-allotment option in full.
 
Units outstanding after this
offering
7,000,000 common units and 7,000,000 subordinated units, each representing a 49% limited partner interest in us.
 
Use of proceeds We intend to use the net proceeds of this offering to:
 
• make a $75.6 million cash distribution to Holly Corporation and its affiliates, in part to reimburse them for certain capital expenditures;
 
• repay $30.1 million of debt we owe to Holly Corporation;
 
• provide $10.0 million in working capital; and
 
• pay $3.0 million of expenses associated with the offering and related formation transactions.
 
At the closing of this offering, we will borrow $25.0 million under our credit agreement to fund an additional cash distribution to Holly Corporation.
 
The net proceeds from any exercise of the underwriters’ over-allotment option will be used to redeem from Holly Corporation and its affiliates a number of common units equal to the number of common units issued upon exercise of the over-allotment option at a price per common unit equal to the proceeds per common unit before expenses but after underwriting discounts and commissions.
 
Cash distributions We intend to make minimum quarterly distributions of $0.50 per unit to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. In general, we will pay any cash distributions we make each quarter in the following manner:
 
• first, 98% to the holders of common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.50 plus any arrearages from prior quarters;
 
• second, 98% to the holders of subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.50; and
 
• third, 98% to all unitholders, pro rata, and 2% to the general partner, until each unit has received a distribution of $0.55.
 
If cash distributions exceed $0.55 per unit in a quarter, our general partner will receive increasing percentages, up to

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50%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” Please read “Cash Distribution Policy.”
 
We must distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner in its discretion. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement and in the glossary of terms attached as Appendix C. The amount of available cash may be greater than or less than the minimum quarterly distribution.
 
We believe that, based on the assumptions listed on page 46 of this prospectus, we will have sufficient cash from operations to make the minimum quarterly distribution of $0.50 on all units for each quarter through June 30, 2005. The amount of pro forma cash available for distribution generated during 2003 would have been sufficient to allow us to pay the full minimum quarterly distribution on the common units, but would not have been sufficient to allow us to pay the full minimum quarterly distribution on the subordinated units, during this period. The amount of pro forma cash available for distribution generated during the three months ended March 31, 2004 would have been sufficient to allow us to pay the full minimum quarterly distribution on all of the units during this period. Please read “Cash Available for Distribution.”
 
Subordination Period During the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. The subordination period will end once we meet the financial tests in the partnership agreement, but it generally cannot end before June 30, 2009. When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages.
 
Issuance of additional units In general, during the subordination period we can issue up to 3,500,000 additional common units, or 50% of the common units outstanding immediately after this offering, without obtaining unitholder approval. We can also issue an unlimited number of common units in connection with acquisitions and capital improvements that increase cash flow from operations per unit on an estimated pro forma basis. We can also issue additional common units if the proceeds are used to repay certain of our indebtedness. Please read “Units Eligible for Future Sale” and “The Partnership Agreement — Issuance of Additional Securities.”
 
Limited voting rights Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business.

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You will have no right to elect our general partner or the directors of its general partner on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66 2/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, our general partner and its affiliates will own an aggregate of 57.1% of our common and subordinated units. This will give our general partner the practical ability to prevent its involuntary removal. Please read “The Partnership Agreement — Voting Rights.”
 
Limited call right If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price not less than the then-current market price of the common units.
 
Estimated ratio of taxable income
to distributions
We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2007, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $2.00 per unit, we estimate that your allocable federal income tax per year will be no more than $0.40 per unit. Please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions” for the basis of this estimate.
 
Exchange listing The common units have been approved for listing on the New York Stock Exchange, subject to official notice of issuance, under the symbol “HEP.”

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Summary Historical and Operating Data

and Pro Forma Financial Data

       The following table sets forth summary historical financial and operating data of Navajo Pipeline Co., L.P. (Predecessor), the predecessor to Holly Energy Partners, L.P., and pro forma financial data of Holly Energy Partners, L.P., in each case for the periods and as of the dates indicated.

       Historical Results. The summary historical financial data for our predecessor for 2001, 2002 and 2003 are derived from the audited consolidated combined financial statements of Navajo Pipeline Co., L.P. (Predecessor) that are included in this prospectus. The summary historical financial data for our predecessor for the three months ended March 31, 2003 and 2004 are derived from the unaudited consolidated combined financial statements of Navajo Pipeline Co., L.P. (Predecessor) that are included in this prospectus. In reviewing this data, you should be aware of the following:

       Until January 1, 2004, our historical revenues included only actual amounts received from:

  •  third parties who utilized our pipelines and terminals;
 
  •  Holly Corporation for use of our FERC-regulated refined product pipeline; and
 
  •  Holly Corporation for use of the Lovington crude oil pipelines, which are not being contributed to our partnership.

       Until January 1, 2004, we did not record revenue for:

  •  transporting products for Holly Corporation on our intrastate refined product pipelines;
 
  •  providing terminalling services to Holly Corporation; and
 
  •  transporting crude oil and feedstocks on two intermediate product pipelines that connect Holly Corporation’s Artesia and Lovington facilities, which are not being contributed to our partnership.

       In addition, our historical results of operations reflect the impact of the following acquisitions completed in June 2003:

  •  the purchase of an additional 45% interest in the Rio Grande Pipeline Company on June 30, 2003, bringing our total ownership to 70%, which resulted in our consolidating the Rio Grande Pipeline Company from the date of this acquisition rather than accounting for it on the equity method; and
 
  •  the purchase of terminals in Spokane, Washington, and Boise and Burley, Idaho, as well as the Woods Cross truck rack, all of which are related to the Woods Cross refinery.

       Furthermore, the historical financial data do not reflect any general and administrative expenses as Holly Corporation has not historically allocated any of its general and administrative expenses to its pipelines and terminals. Our historical results of operations include costs associated with crude oil and intermediate product pipelines that are not being contributed to our partnership.

       Pro Forma Results. The summary pro forma financial data presented below as of March 31, 2004 and for the year ended December 31, 2003 and the three months ended March 31, 2004 are derived from the pro forma financial statements that are included in this prospectus. The pro forma financial data give pro forma effect to:

  •  the transfer of certain of our predecessor’s operations to Holly Energy Partners, L.P.;
 
  •  the consolidation of the Rio Grande Pipeline Company as if the additional 45% interest had been acquired as of January 1, 2003;

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  •  the execution of the pipelines and terminals agreement; and
 
  •  the related transactions in connection with the closing of this offering.

       The pro forma balance sheet assumes that the offering and the related transactions occurred as of March 31, 2004 and the pro forma statements of income assume that the offering and the related transactions occurred as of January 1, 2003.

       The pro forma financial data for the year ended December 31, 2003 reflect the revenues that would have been recorded in 2003, using historical volumes, if the initial tariff rates and terminalling fees in the pipelines and terminals agreement had been in effect for the entire year. Because we began charging Holly Corporation fees at the rates set forth in the pipelines and terminals agreement for the use of all of our pipelines and terminals commencing January 1, 2004, the pro forma financial data for the three months ended March 31, 2004 reflect actual revenues received from Holly Corporation. We believe that our pipeline tariffs and terminalling fees are comparable to those that would be charged by third parties in the specific marketing locations. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Impact of Pipelines and Terminals Agreement.”

       The pro forma financial data do not reflect either the $2.0 million administrative fee that Holly Corporation will charge us under the omnibus agreement or the estimated $1.7 million in additional general and administrative expenses we expect to incur as a result of being a separate public entity.

       Non-GAAP and Other Financial Information. The following table presents a non-GAAP financial measure: earnings before interest, taxes, depreciation and amortization, or EBITDA, which we use in our business. We explain this measure below and reconcile it to net income and cash flow from operating activities, our most directly comparable financial measures calculated and presented in accordance with GAAP.

       Maintenance capital expenditures represent capital expenditures to replace partially or fully depreciated assets to maintain the operating capacity of existing assets and extend their useful lives. Expansion capital expenditures represent capital expenditures to expand the operating capacity of existing or new assets, whether through construction or acquisition. Repair and maintenance expenses associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred.

       Use of the term “throughput” in this prospectus generally refers to the refined product barrels that pass through each pipeline or terminal facility, even if those barrels are transported or pass through another of our pipeline or terminal facilities, for which we receive either pipeline tariff or terminal service fee revenue.

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       The following table should be read together with, and is qualified in its entirety by reference to, the historical and unaudited pro forma financial statements and the accompanying notes included elsewhere in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

                                                             
Holly Energy Partners, L.P.

Navajo Pipeline Co., L.P. (Predecessor) Pro Forma


Three Months Three Months
Ended Year Ended Ended
Years Ended December 31, March 31, December 31, March 31,




2001 2002 2003 2003 2004 2003 2004







(In thousands, except per unit data)
STATEMENT OF INCOME DATA:
                                                       
Revenue
  $ 20,647     $ 23,581     $ 30,800     $ 5,662     $ 18,771     $ 52,707     $ 15,432  
Operating costs and expenses
                                                       
 
Operations
    17,388       19,442       24,193       5,166       6,452       21,550       5,228  
 
Selling, general and administrative
                                           
 
Depreciation and amortization
    3,740       4,475       6,453       1,179       2,046       6,928       1,834  
     
     
     
     
     
     
     
 
   
Total operating costs and expenses
    21,128       23,917       30,646       6,345       8,498       28,478       7,062  
     
     
     
     
     
     
     
 
Operating income (loss)
    (481 )     (336 )     154       (683 )     10,273       24,229       8,370  
Interest expense
                                  (1,750 )     (437 )
Equity income from Rio Grande Pipeline Company
    2,284       2,737       894       285                    
Interest and other income
    620       269       291       37       35       308       35  
     
     
     
     
     
     
     
 
      2,904       3,006       1,185       322       35       (1,442 )     (402 )
     
     
     
     
     
     
     
 
Income before minority interest
    2,423       2,670       1,339       (361 )     10,308       22,787       7,968  
Minority interest in Rio Grande Pipeline Company
                (758 )           (688 )     (1,405 )     (688 )
     
     
     
     
     
     
     
 
Net income
  $ 2,423     $ 2,670     $ 581     $ (361 )   $ 9,620     $ 21,382     $ 7,280  
     
     
     
     
     
     
     
 
Pro forma net income per limited partner unit
                                          $ 1.50     $ 0.51  
                                             
     
 
OTHER FINANCIAL DATA:
                                                       
EBITDA
  $ 5,543     $ 6,876     $ 6,743     $ 781     $ 11,631     $ 29,752     $ 9,516  
     
     
     
     
     
     
     
 
Cash flows from operating activities
  $ 10,273     $ 4,271     $ 5,909     $ 187     $ 283                  
     
     
     
     
     
                 
Cash flows from investment activities
  $ (10,273 )   $ (4,271 )   $ (29,297 )   $ (187 )   $ (2,599 )                
     
     
     
     
     
                 
Cash flows from financing activities
  $     $     $ 30,082     $     $                  
     
     
     
     
     
                 
Maintenance capital expenditures
  $ 760     $ 1,178     $ 1,934     $ 187     $ 558                  
Expansion capital expenditures
    10,756       5,581       4,837     $     $ 991                  
     
     
     
     
     
                 
Total capital expenditures
  $ 11,516     $ 6,759     $ 6,771     $ 187     $ 1,549                  
     
     
     
     
     
                 
OPERATING DATA (bbls):
                                                       
Refined product pipeline throughput
    21,992       25,127       23,978       5,904       7,095                  
Refined product terminal throughput
    30,302       34,435       40,147       7,791       12,866                  
BALANCE SHEET DATA: (at period end)
                                                       
Net property, plant and equipment
  $ 57,801     $ 60,073     $ 95,826     $ 58,930     $ 95,890             $ 81,927  
Total assets
    84,282       88,338       140,425       89,296       147,588               130,286  
Total liabilities
    18,674       20,059       57,889       21,377       54,994               48,334  
Net partners’ investment
    65,609       68,279       68,860       67,920       78,480               67,838  

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Non-GAAP Financial Measure

       EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors and commercial banks, to assess:

  •  the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
 
  •  the ability of our assets to generate cash sufficient to pay interest on our indebtedness and to make distributions to our partners;
 
  •  our operating performance and return on invested capital as compared to those of other companies in the logistics business, without regard to financing methods and capital structure; and
 
  •  our compliance with certain financial covenants included in our debt agreements.

       EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA excludes some, but not all, items that affect net income and operating income, and these measures may vary among other companies. Therefore, EBITDA as presented below may not be comparable to similarly titled measures of other companies.

       The following table presents a reconciliation of EBITDA to the most directly comparable GAAP financial measures, on a historical basis and pro forma basis, as applicable, for each of the years indicated.

                                                             
Holly Energy Partners, L.P.

Navajo Pipeline Co., L.P. (Predecessor)

Pro Forma

Three Months Three Months
Ended Year Ended Ended
Years Ended December 31, March 31, December 31, March 31,




2001 2002 2003 2003 2004 2003 2004







(In thousands)
Reconciliation of EBITDA to net income:
                                                       
 
Net income
  $ 2,423     $ 2,670     $ 581     $ (361 )   $ 9,620     $ 21,382     $ 7,280  
 
Add
                                                       
   
Depreciation and amortization
    3,740       4,475       6,453       1,179       2,046       6,928       1,834  
   
Interest expense
                                  1,750       437  
     
     
     
     
     
     
     
 
      6,163       7,145       7,034       818       11,666       30,060       9,551  
 
Less
                                                       
   
Interest income
    620       269       291       37       35       308       35  
     
     
     
     
     
     
     
 
EBITDA
  $ 5,543     $ 6,876     $ 6,743     $ 781     $ 11,631     $ 29,752     $ 9,516  
     
     
     
     
     
     
     
 
Reconciliation of EBITDA to cash flows from operating activities:
                                                       
 
Cash flow from operating activities
  $ 10,273     $ 4,271     $ 5,909     $ 187     $ 283                  
 
Add
                                                       
   
Interest income
    (620 )     (269 )     (291 )     (37 )     (35 )                
   
Equity in earnings of Rio Grande Pipeline Company
    2,284       2,737       894       285                        
   
Minority interest
                (758 )           (688 )                
   
Increase (decrease) in working capital
    (6,394 )     137       989       346       12,071                  
     
     
     
     
     
                 
EBITDA
  $ 5,543     $ 6,876     $ 6,743     $ 781     $ 11,631                  
     
     
     
     
     
                 

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RISK FACTORS

       Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

       If any of the following risks were actually to occur, our business, financial condition, or results of operations could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline, and you could lose all or part of your investment.

Risks Inherent in Our Business

 
We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.

       We may not have sufficient available cash each quarter to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

  •  the volume of refined products transported in our pipelines or handled at our terminals;
 
  •  the tariff rates and terminalling fees we charge;
 
  •  the level of our operating costs, including payments to our general partner; and
 
  •  prevailing economic conditions.

       In addition, the actual amount of cash we will have available for distribution will depend on other factors such as:

  •  the level of capital expenditures we make;
 
  •  the restrictions contained in our credit agreement;
 
  •  our debt service requirements;
 
  •  the cost of acquisitions, if any;
 
  •  fluctuations in our working capital needs;
 
  •  our ability to borrow under our credit agreement to make distributions to our unitholders; and
 
  •  the amount, if any, of cash reserves established by our general partner in its discretion.
 
The amount of cash we have available for distribution to unitholders depends primarily on our cash flow and not solely on profitability.

       You should be aware that the amount of cash we have available for distribution depends primarily on our cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.

       The amount of available cash we need to pay the minimum quarterly distribution for four quarters on the common units, the subordinated units and the general partner interest to be outstanding immediately after this offering is approximately $28.6 million. Estimated available

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cash from operating surplus generated during 2003 would have been sufficient to allow us to pay the full minimum quarterly distribution on the common units, but insufficient by $5.9 million to pay the full minimum quarterly distribution on the subordinated units during this period. For a calculation of our ability to make distributions to unitholders based on our pro forma results in 2003 and the three months ended March 31, 2004, please read “Cash Available for Distribution” and Appendix D.
 
We depend upon Holly Corporation and particularly its Navajo Refinery for a substantial majority of our revenues and if those revenues were reduced, there would be a material adverse effect on our results of operations and ability to make distributions to unitholders.

       For the year ended December 31, 2003, Holly Corporation accounted for approximately 53.6% of the pro forma revenues of our pipelines and approximately 73.0% of the pro forma revenues of our terminals. We expect to continue to derive a substantial majority of our revenues from Holly Corporation for the foreseeable future. If Holly Corporation satisfies only its minimum obligations under the pipelines and terminals agreement or is unable to meet its minimum revenue commitment for any reason, including due to prolonged downtime or a shutdown at the Navajo Refinery or the Woods Cross Refinery, our revenues would decline and our ability to make distributions to unitholders would be adversely affected. Please read “Certain Relationships and Related Party Transactions — Pipelines and Terminals Agreement” for more information regarding our relationship with Holly Corporation.

       Any significant curtailing of production at the Navajo Refinery could, by reducing throughput in our pipelines, result in our realizing materially lower levels of revenues and cash flow for the duration of the shutdown. For the year ended December 31, 2003 and the three months ended March 31, 2004, production from the Navajo Refinery accounted for approximately 78.3% and 83.8%, respectively, of the throughput volumes transported by our pipelines that serve the Navajo Refinery. Operations at the Navajo Refinery could be partially or completely shut down, temporarily or permanently, as the result of:

  •  competition from other refineries and pipelines that may be able to supply Holly Corporation’s end-user markets on a more cost-effective basis;
 
  •  operational problems such as catastrophic events at the refinery, labor difficulties or environmental proceedings or other litigation that compel the cessation of all or a portion of the operations at the refinery;
 
  •  increasingly stringent environmental regulations, such as the Environmental Protection Agency’s gasoline and diesel sulfur control requirements that limit the concentration of sulfur in motor gasoline and diesel fuel;
 
  •  an inability to obtain crude oil for the refinery at competitive prices;
 
  •  a general reduction in demand for refined products in the area due to:

  •  a local or national recession or other adverse economic condition that results in lower spending by businesses and consumers on gasoline, diesel fuel and travel;
 
  •  higher gasoline prices due to higher crude oil prices, higher taxes or stricter environmental regulations; or
 
  •  a shift by consumers to more fuel-efficient or alternative fuel vehicles or an increase in fuel economy, whether as a result of technological advances by manufacturers, legislation mandating higher fuel economy or otherwise.

The magnitude of the effect on us of any shutdown will depend on the length of the shutdown and the extent of the refinery operations affected by the shutdown. We have no control over the

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factors that may lead to a shutdown or the measures Holly Corporation may take in response to a shutdown.

We have no control over the operation of Holly Corporation’s Navajo Refinery.

       Holly Corporation will make all decisions at the Navajo Refinery concerning levels of production, regulatory compliance, planned shutdowns of individual process units within the refinery to perform major maintenance activities, also referred to as “refinery turnarounds,” labor relations, environmental remediation and capital expenditures and is under no contractual obligation to us to maintain operations at the Navajo Refinery.

       Furthermore, Holly Corporation’s obligations under the pipelines and terminals agreement would be temporarily suspended during the occurrence of an event outside the control of the parties that renders performance impossible with respect to an asset for at least 30 days. If such an event were to continue for a year, we or Holly Corporation could terminate the pipelines and terminals agreement. The occurrence of any of these events could reduce our revenues and cash flows, and our ability to make distributions to our unitholders.

 
Competition from other pipelines that may be able to supply Holly Corporation’s customers with refined products at a lower price, including the Longhorn Pipeline, which may become operational late in the summer of 2004, could cause us to reduce our rates or could reduce our revenues.

       We and Holly Corporation face competition from other pipelines that may be able to supply Holly Corporation’s end-user markets with refined products on a more competitive basis. One particular pipeline project, the Longhorn Pipeline, could provide significant competition. The Longhorn Pipeline is a common carrier pipeline that will be capable of delivering refined products utilizing a direct route from the Texas Gulf Coast to El Paso and, through interconnections with third party common carrier pipelines, into the Arizona market. In April 2004, Longhorn officials stated they had received the additional financing needed to finalize the project. Recent reports suggest that Longhorn officials expect startup to occur late in the summer of 2004. If the Longhorn Pipeline operates as currently proposed, it could result in significant downward pressure on wholesale refined product prices and refined product margins in El Paso and related markets. Additionally, the increased supply of refined products entering the El Paso and Arizona markets on this pipeline and the likely increase in the demand for shipping product on the interconnecting common carrier pipelines, which are currently capacity constrained, could cause a decline in the demand for refined product from Holly Corporation, which could ultimately result in a reduction in Holly Corporation’s minimum revenue commitment to us. Holly Corporation’s results of operations could be adversely impacted if the Longhorn Pipeline were allowed to operate as currently proposed. It is not possible to predict whether and, if so, under what conditions, the Longhorn Pipeline will ultimately be operated, nor is it possible to predict the consequences for Holly Corporation and Holly Energy Partners of Longhorn Pipeline’s operations if they occur. Please read “Business — Competition — El Paso Market — Longhorn Pipeline.”

       An additional factor that could affect some of Holly Corporation’s markets is excess pipeline capacity from the West Coast into Holly Corporation’s Arizona markets after the elimination of bottlenecks in 2000 on the pipeline from the West Coast to Phoenix. If refined products become available on the West Coast in excess of demand in that market, additional products could be shipped into Holly Corporation’s Arizona markets with resulting possible downward pressure on refined products prices in these markets. Please read “Business — Competition — Arizona and Albuquerque Markets.”

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A material decrease in the supply, or a material increase in the price, of crude oil available to Holly Corporation’s refineries, could materially reduce our ability to make distributions to unitholders.

       The volume of refined products we transport in our refined product pipelines depends on the level of production of refined products from Holly Corporation’s refineries, which, in turn, depends on the availability of attractively-priced crude oil produced in the areas accessible to Holly Corporation’s refineries. In order to maintain or increase production levels at its refineries, Holly Corporation must continually contract for new crude oil supplies. A material decrease in crude oil production from the fields that supply Holly Corporation’s refineries, as a result of depressed commodity prices, lack of drilling activity, natural production declines or otherwise, could result in a decline in the volume of crude oil it refines. Such an event would result in an overall decline in volumes of refined products transported through our pipelines and therefore a corresponding reduction in our cash flow. In addition, Holly Corporation’s future growth will depend in part upon whether it can contract for additional supplies of crude oil at a greater rate than the rate of natural decline in its currently connected supplies. Please read “Business — Holly Corporation’s Refining Operations” for more information regarding the sources of crude oil that supply Holly Corporation’s refineries.

       Fluctuations in crude oil prices can greatly affect production rates and investments by third parties in the development of new oil reserves. Drilling activity generally decreases as crude oil prices decrease. We and Holly Corporation have no control over the level of drilling activity in the areas of operations, the amount of reserves underlying the wells and the rate at which production from a well will decline or producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, geological considerations, governmental regulation and the availability and cost of capital. Similarly, if there were a material increase in the price of crude oil supplied to Holly Corporation’s refineries without an increase in the value of the products produced by the refineries, either temporary or permanent, which caused Holly Corporation to reduce production of refined products at its refineries, this would cause a reduction in the volumes of refined products we transport and our cash flow.

 
We are exposed to the credit risks of our key customers, including Holly Corporation, and any material nonpayment or nonperformance by our key customers could reduce our ability to make distributions to our unitholders.

       We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Any material nonpayment or nonperformance by our key customers, including Holly Corporation, could reduce our ability to make distributions to our unitholders. In addition to revenues received from Holly Corporation under our pipelines and terminals agreement, we derived approximately 12.0% of our pro forma revenues in 2003 from a contract with Alon USA, LP, which leases 20,000 bpd of capacity on our Artesia-Orla-El Paso pipeline. In addition, a subsidiary of BP is the only shipper on the Rio Grande pipeline, a joint venture in which we own a 70% interest and from which we derived approximately 25.6% of our pro forma revenues in 2003.

       If any of our key customers default on their obligations to us, our financial results could be adversely affected. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks. Any loss of our key customers, including Holly Corporation, could reduce our ability to make distributions to our unitholders.

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We may not be able to retain existing customers or acquire new customers, which would reduce our revenues and limit our future profitability.

       The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors outside our control, including competition from other pipelines and the demand for refined products in the markets that we serve. Alon USA’s obligations to lease capacity on the Artesia-Orla-El Paso pipeline have remaining terms ranging from four to seven years. BP’s agreement to ship on the Rio Grande Pipeline expires in 2007. If we are unable to renew or replace our current contracts as they expire, our ability to make distributions to our unitholders could be adversely affected.

 
Due to our lack of asset diversification, adverse developments in our pipelines and terminals business would reduce our ability to make distributions to our unitholders.

       We rely exclusively on the revenues generated from our pipelines and terminals business. Due to our lack of asset diversification, an adverse development in this business would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets.

 
Our operations are subject to federal, state, and local laws and regulations relating to environmental protection and operational safety that could require us to make substantial expenditures.

       Our pipelines and terminal operations are subject to increasingly strict environmental and safety laws and regulations. The transportation and storage of refined products result in a risk that refined products and other hydrocarbons may be suddenly or gradually released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resources damages, personal injury, or property damages to private parties and significant business interruption. We own or lease a number of properties that have been used to store or distribute refined products for many years. Many of these properties have also been operated by third parties whose handling, disposal, or release of hydrocarbons and other wastes were not under our control. Please read “Business — Environmental Regulation” and “— Environmental Remediation” for more information.

 
Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

       Our operations are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, mechanical failures and other events beyond our control. These events might result in a loss of equipment or life, injury, or extensive property damage, as well as an interruption in our operations. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, our insurance carriers require broad exclusions for losses due to terrorist acts. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position.

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Any reduction in the capacity of, or the allocations to, our shippers in interconnecting, third-party pipelines could cause a reduction of volumes transported in our pipelines and through our terminals, which would reduce our ability to make distributions to our unitholders.

       Holly Corporation and the other users of our pipelines and terminals are dependent upon connections to third-party pipelines to receive and deliver crude oil and refined products. Any reduction of capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes transported in our pipelines or through our terminals. Similarly, if additional shippers begin transporting volumes of refined products over interconnecting pipelines, the allocations to existing shippers in these pipelines would be reduced, which could also reduce volumes transported in our pipelines or through our terminals. For example, the common carrier pipelines used by Holly Corporation to serve the Arizona and Albuquerque markets are currently operated at or near capacity and are subject to proration. As a result, the volumes of refined product Holly Corporation and other shippers have been able to deliver to these markets have been limited. The flow of additional products into El Paso for shipment to Arizona, either as a result of operation of the Longhorn Pipeline or otherwise, could further exacerbate such constraints on deliveries to Arizona. Any reduction in volumes transported in our pipelines or through our terminals would adversely affect our revenues and cash flow.

 
If we do not make acquisitions on economically acceptable terms, any future growth will be limited.

       Our ability to grow and to increase distributions to unitholders is principally dependent on our ability to make acquisitions that result in an increase in adjusted operating surplus per unit. If we are unable to make such accretive acquisitions either because we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them or because we are unable to raise financing for such acquisitions on economically acceptable terms or because we are outbid by competitors, our future growth and ability to raise distributions will be limited. Furthermore, even if we do consummate acquisitions that we believe will be accretive, they may in fact turn out to result in a decrease in adjusted operating surplus per unit. Any acquisition involves potential risks, including, among other things:

  •  mistaken assumptions about revenues and costs, including synergies;
 
  •  the assumption of unknown liabilities;
 
  •  limitations on rights to indemnity from the seller;
 
  •  the diversion of management’s attention from other business concerns;
 
  •  unforeseen difficulties operating in new product areas or new geographic areas; and
 
  •  customer or key employee losses at the acquired businesses.
 
If our assumptions concerning population growth are inaccurate or if Holly Corporation’s growth strategy is not successful, our ability to make or increase distributions to unitholders may be adversely affected.

       Our growth strategy is dependent upon:

  •  the accuracy of our assumption that many of the markets that we serve in the Southwestern and Rocky Mountain regions of the United States will experience population growth that is higher than the national average; and
 
  •  the willingness and ability of Holly Corporation to capture a share of this additional demand in its existing markets and to identify and penetrate new markets in the Southwestern and Rocky Mountain regions of the United States.

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       If our assumptions about growth in market demand prove incorrect, Holly Corporation may not have any incentive to increase refinery capacity and production or shift additional throughput to our pipelines, which would adversely affect our growth strategy. Furthermore, Holly Corporation is under no obligation to pursue a growth strategy. If Holly Corporation chooses not to, or is unable to, gain additional customers in new or existing markets in the Southwestern and Rocky Mountain regions of the United States, our growth strategy would be adversely affected. Moreover, Holly Corporation may not make acquisitions that would provide acquisition opportunities to us, or if those opportunities arose, they may not be on terms attractive to us. Finally, Holly Corporation also will be subject to integration risks with respect to any new acquisitions it chooses to make.

 
Growing our business by constructing new pipelines and terminals, or expanding existing ones, subjects us to construction risks.

       One of the ways we may grow our business is through the construction of new pipelines and terminals or the expansion of existing ones. We have no material commitments for new construction or expansion projects as of the date of this prospectus. The construction of a new pipeline or the expansion of an existing pipeline, by adding horsepower or pump stations or by adding a second pipeline along an existing pipeline, involves numerous regulatory, environmental, political, and legal uncertainties, most of which are beyond our control. These projects may not be completed on schedule or at all or at the budgeted cost. In addition, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time and we will not receive any material increases in revenues until after completion of the project. Moreover, we may construct facilities to capture anticipated future growth in demand for refined products in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

 
Restrictions in our credit agreement may prevent us from engaging in some beneficial transactions or paying distributions.

       Various limitations in our credit agreement may reduce our ability to incur additional debt, engage in some transactions, and capitalize on acquisition or other business opportunities. Our revolving credit agreement will contain provisions relating to changes in ownership. If these provisions are triggered, the outstanding debt may become due. If that happens, we may not be able to pay the debt. In addition, we will be prohibited by our credit agreement from making cash distributions during an event of default, or if the payment of a distribution would cause an event of default, under any of our debt agreements. Further, termination of our pipelines and terminals agreement or omnibus agreement prior to its expiration will constitute an event of default under our credit facility. Borrowings under our bank credit facility that are used to pay distributions to unitholders may not exceed $5,000,000 at any one time. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Agreement.”

 
Rate regulation may not allow us to recover the full amount of increases in our costs.

       The primary rate-making methodology of the Federal Energy Regulatory Commission, or FERC, is price indexing. We use this methodology in all of our interstate markets. The indexing method allows a pipeline to increase its rates by a percentage equal to the change in the producer price index for finished goods. If the index falls, we will be required to reduce our rates that are based on the FERC’s price indexing methodology if they exceed the new maximum allowable rate. In addition, changes in the index might not be large enough to fully reflect actual increases in our costs. The FERC’s rate-making methodologies may limit our ability to set rates

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based on our true costs or may delay the use of rates that reflect increased costs. Any of the foregoing would adversely affect our revenues and cash flow.
 
If our interstate or intrastate tariff rates are successfully challenged, we could be required to reduce our tariff rates, which would reduce our revenues and our ability to make distributions to our unitholders.

       Under the Energy Policy Act adopted in 1992, our interstate pipeline rates were deemed just and reasonable or “grandfathered.” As that Act applies to our rates, a person challenging a grandfathered rate must, as a threshold matter, establish that a substantial change has occurred since the date of enactment of the Act, in either the economic circumstances or the nature of the service that formed the basis for the rate. A complainant might assert that the creation of the partnership itself constitutes such a change, an argument that has not previously been specifically addressed by the FERC. If the FERC were to find a substantial change in circumstances, then our existing rates could be subject to detailed review. If our rates were found to be in excess of levels justified by our cost of service the FERC could order us to reduce our rates. In addition, a state commission could also investigate our intrastate rates or our terms and conditions of service on its own initiative or at the urging of a shipper or other interested party. If a state commission found that our rates exceeded levels justified by our cost of service, the state commission could order us to reduce our rates. Any such reductions would result in lower revenues and cash flows and would reduce our ability to make distributions to our unitholders. Please read “Business — Rate Regulation” for more information on our tariff rates.

       Holly Corporation has agreed not to challenge, or to cause others to challenge or assist others in challenging, our tariff rates in effect during the term of the pipelines and terminals agreement. This agreement does not prevent other current or future shippers from challenging our tariff rates. At the end of the term of the agreement, Holly Corporation will be free to challenge, or to cause other parties to challenge or assist others in challenging, our tariff rates in effect at that time. If any party successfully challenges our tariff rates, the effect would be to reduce our ability to make distributions to our unitholders.

 
Potential changes to current petroleum pipeline rate-making methods and procedures may impact the federal and state regulations under which we will operate in the future.

       If the FERC’s petroleum pipeline rate-making methodology changes, the new methodology could result in tariffs that generate lower revenues and cash flow and adversely affect our ability to make cash distributions to our unitholders.

 
Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.

       The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks, on the energy transportation industry in general, and on us in particular, is not known at this time. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror.

       Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

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An adverse decision in a lawsuit pending between Holly Corporation and Frontier Oil Corporation could have a material adverse effect on Holly Corporation’s financial condition and therefore on our results of operations.

       On August 20, 2003, Frontier Oil Corporation filed a lawsuit in the Delaware Court of Chancery seeking declaratory relief and unspecified damages based on allegations that Holly Corporation repudiated its obligations and breached an implied covenant of good faith and fair dealing under a merger agreement announced in late March 2003 under which Frontier and Holly Corporation were to be combined. On September 2, 2003, Holly Corporation filed its answer and counterclaims seeking declaratory judgments that Holly Corporation had not repudiated the merger agreement, that Frontier had repudiated the merger agreement, that Frontier had breached certain representations made by Frontier in the merger agreement, that Holly Corporation’s obligations under the merger agreement were and are excused and that Holly Corporation may terminate the merger agreement without liability, and seeking unspecified damages as well as costs and attorneys’ fees. The trial with respect to Frontier’s complaint and the Holly Corporation answer and counterclaims began in the Delaware Court of Chancery on February 23, 2004 and was completed on March 5, 2004. In this litigation, the maximum amount of damages currently asserted by Frontier against Holly Corporation is approximately $161 million plus interest and the maximum amount of damages currently asserted by Holly Corporation against Frontier is approximately $148 million plus interest. Post-trial briefing was completed in late April 2004 and on May 4, 2004 the court heard oral argument. We expect a decision to be announced by the court within several months. While we cannot predict the outcome of this litigation, an adverse decision to Holly Corporation could have a material adverse effect on Holly Corporation’s business, financial condition, liquidity, competitive position or prospects. Because we depend upon Holly Corporation for a substantial majority of our revenues, if an adverse decision to Holly Corporation reduced the volumes it transports on our pipelines or its ability to make payments to us under the pipelines and terminals agreement, our results of operations, financial condition and business could be materially adversely affected.

Risks Inherent in an Investment in Us

 
Holly Corporation and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to your detriment.

       Following the offering, Holly Corporation will indirectly own the 2% general partner interest and a 56% limited partner interest in us and will own and control our general partner. Conflicts of interest may arise between Holly Corporation and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, the general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

  •  Holly Corporation, as a shipper on our pipelines, has an economic incentive not to cause us to seek higher tariff rates or terminalling fees, even if such higher rates or terminalling fees would reflect rates that could be obtained in arm’s-length, third-party transactions;
 
  •  neither our partnership agreement nor any other agreement requires Holly Corporation to pursue a business strategy that favors us or utilizes our assets, including whether to increase or decrease refinery production, whether to shut down or reconfigure a refinery, or what markets to pursue or grow. Holly Corporation’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of Holly Corporation;
 
  •  our general partner is allowed to take into account the interests of parties other than us, such as Holly Corporation, in resolving conflicts of interest;

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  •  our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;
 
  •  our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities, and reserves, each of which can affect the amount of cash that is distributed to our unitholders;
 
  •  our general partner determines which costs incurred by Holly Corporation and its affiliates are reimbursable by us;
 
  •  our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
 
  •  our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including the pipelines and terminals agreement with Holly Corporation; and
 
  •  our general partner decides whether to retain separate counsel, accountants, or others to perform services for us.

       Please read “Certain Relationships and Related Party Transactions — Omnibus Agreement” and “Conflicts of Interest and Fiduciary Duties.”

 
Cost reimbursements, which will be determined by our general partner, and fees due our general partner and its affiliates for services provided will be substantial and will reduce our cash available for distribution to you.

       Payments to our general partner will be substantial and will reduce the amount of available cash for distribution to unitholders. For three years following this offering, we will pay Holly Corporation an administrative fee of $2.0 million per year for the provision by Holly Corporation or its affiliates of various general and administrative services for our benefit. The administrative fee may increase in the second and third years by the greater of 5% or the percentage increase in the consumer price index and may also increase if we make an acquisition that requires an increase in the level of general and administrative services that we receive from Holly Corporation or its affiliates. In addition, the general partner and its affiliates will be entitled to reimbursement for all other expenses they incur on our behalf, including the salaries of and the cost of employee benefits for employees of Holly Logistic Services, L.L.C. who provide services to us. Our general partner will determine the amount of these expenses. Our general partner and its affiliates also may provide us other services for which we will be charged fees as determined by our general partner. Please read “Conflicts of Interest and Fiduciary Duties — Conflicts of Interest.”

 
Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

       Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:

  •  permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;

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  •  provides that our general partner is entitled to make other decisions in “good faith” if it reasonably believes that the decision is in our best interests;
 
  •  generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner’s general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and
 
  •  provides that our general partner, its general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence.

       In order to become a limited partner of our partnership, a common unitholder is required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties”.

 
Even if unitholders are dissatisfied, they cannot remove our general partner without its consent.

       Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect our general partner or the board of directors of our general partner’s general partner and will have no right to elect our general partner or the board of directors of our general partner’s general partner on an annual or other continuing basis. The board of directors of our general partner’s general partner is chosen by the members of our general partner’s general partner. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

       The unitholders will be unable initially to remove the general partner without its consent because the general partner and its affiliates will own sufficient units upon completion of the offering to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove the general partner. Following the closing of this offering, the general partner and its affiliates will own 57.1% of the units. Also, if the general partner is removed without cause during the subordination period and units held by the general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on the common units will be extinguished. A removal of the general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud, gross negligence, or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of the general partner because of the unitholders’ dissatisfaction with the general partner’s performance in managing our partnership will most likely result in the termination of the subordination period.

       Furthermore, unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units

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then outstanding, other than the general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of the general partner’s general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
 
The control of our general partner may be transferred to a third party without unitholder consent.

       Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the partners of our general partner from transferring their respective partnership interests in our general partner to a third party. The new partners of our general partner would then be in a position to replace the board of directors and officers of the general partner of our general partner with their own choices and to control the decisions taken by the board of directors and officers.

 
You will experience immediate and substantial dilution of $16.94 per common unit.

       The assumed initial public offering price of $21.25 per unit exceeds pro forma net tangible book value of $4.31 per unit. Based on an assumed initial public offering price of $21.25 per unit, you will incur immediate and substantial dilution of $16.94 per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded at their historical cost, and not their fair value, in accordance with generally accepted accounting principles. Please read “Dilution.”

 
We may issue additional common units without your approval, which would dilute your ownership interests.

       During the subordination period, our general partner, without the approval of our unitholders, may cause us to issue up to 3,500,000 additional common units. Our general partner may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without unitholder approval, in a number of circumstances such as:

  •  the issuance of common units upon the exercise of the underwriters’ over-allotment option;
 
  •  the issuance of common units in connection with acquisitions or capital improvements that increase cash flow from operations per unit on an estimated pro forma basis;
 
  •  issuances of common units to repay indebtedness, the cost of which to service is greater than the distribution obligations associated with the units issued in connection with the repayment of the indebtedness;
 
  •  the conversion of subordinated units into common units;
 
  •  the conversion of units of equal rank with the common units into common units under some circumstances;
 
  •  in the event of a combination or subdivision of common units;
 
  •  issuances of common units under our employee benefit plans; or
 
  •  the conversion of the general partner interest and the incentive distribution rights into common units as a result of the withdrawal or removal of our general partner.

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       The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

  •  our unitholders’ proportionate ownership interest in us will decrease;
 
  •  the amount of cash available for distribution on each unit may decrease;
 
  •  because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
 
  •  the relative voting strength of each previously outstanding unit may be diminished; and
 
  •  the market price of the common units may decline.

       After the end of the subordination period, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our partnership agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time.

 
In establishing cash reserves, our general partner may reduce the amount of cash available for distribution to you.

       Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that it establishes are necessary to fund our future operating expenditures. In addition, our partnership agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to you.

 
Holly Corporation and its affiliates may engage in limited competition with us.

       Holly Corporation and its affiliates may engage in limited competition with us. Pursuant to the omnibus agreement, Holly Corporation and its affiliates will agree not to engage in the business of operating intermediate or refined product pipelines or terminals, crude oil pipelines or terminals, truck racks or crude oil gathering systems in the continental United States. The omnibus agreement, however, does not apply to:

  •  any business operated by Holly Corporation or any of its subsidiaries at the closing of this offering;
 
  •  any crude oil pipeline or gathering system acquired or constructed by Holly Corporation or any of its subsidiaries after the closing of the offering that is physically interconnected to Holly Corporation’s refining facilities;
 
  •  any business or asset that Holly Corporation or any of it subsidiaries acquires or constructs that has a fair market value or construction cost of less than $5.0 million; and
 
  •  any business or asset that Holly Corporation or any of its subsidiaries acquires or constructs that has a fair market value or construction cost of $5.0 million or more if we have been offered the opportunity to purchase the business or asset at fair market value, and we decline to do so with the concurrence of our conflicts committee.

       In the event that Holly Corporation or its affiliates no longer control our partnership or there is a change of control of Holly Corporation, the non-competition provisions of the omnibus agreement will terminate.

 
Our general partner may cause us to borrow funds in order to make cash distributions, even where the purpose or effect of the borrowing benefits our general partner or its affiliates.

       In some instances, our general partner may cause us to borrow funds from affiliates of Holly Corporation or from third parties in order to permit the payment of cash distributions.

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These borrowings are permitted even if the purpose and effect of the borrowing is to enable us to make a distribution on the subordinated units, to make incentive distributions, or to hasten the expiration of the subordination period.

 
Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.

       If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the completion of this offering and assuming no exercise of the over-allotment option, our general partner and its affiliates will own approximately 14.3% of the common units. At the end of the subordination period, assuming no additional issuances of common units, our general partner and its affiliates will own approximately 57.1% of the common units. For additional information about this call right, please read “The Partnership Agreement — Limited Call Right.”

 
Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

       A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for our obligations as if you were a general partner if:

  •  a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or
 
  •  your right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

       Please read “The Partnership Agreement — Limited Liability” for a discussion of the implications of the limitations of liability on a unitholder.

 
Unitholders may have liability to repay distributions.

       Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Assignees who become substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the assignee at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

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Tax Risks

       You should read “Material Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

 
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by states. If the IRS were to treat us as a corporation or if we were to become subject to entity-level taxation for state tax purposes, then our cash available for distribution to you would be substantially reduced.

       The anticipated after-tax benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

       If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to you, likely causing a substantial reduction in the value of the common units.

       Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. For example, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced. The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.

 
A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units, and the costs of any contest will be borne by our unitholders and our general partner.

       We have not requested any ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from our counsel’s conclusions expressed in this prospectus. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner.

 
You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

       You will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from your share of our taxable income.

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Tax gain or loss on the disposition of our common units could be different than expected.

       If you sell your common units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to you.

 
Tax-exempt entities, regulated investment companies and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

       Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), regulated investment companies (known as mutual funds), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Very little of our income will be qualifying income to a regulated investment company. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

 
We will register as a tax shelter. This may increase the risk of an IRS audit of us or a unitholder.

       We intend to register as a “tax shelter” with the U.S. Secretary of the Treasury. We will advise you of our tax shelter registration number once that number has been assigned. The IRS requires that some types of entities, including some partnerships, register as tax shelters in response to the perception that they claim tax benefits that the IRS may believe to be unwarranted. As a result, we may be audited by the IRS and tax adjustments could be made. Any unitholder owning less than a 1% profits interest in us has very limited rights to participate in the income tax audit process. Further, any adjustments in our tax returns will lead to adjustments in your tax returns and may lead to audits of your tax returns and adjustments of items unrelated to us. You will bear the cost of any expense incurred in connection with an examination of your personal tax return.

       Recently issued Treasury Regulations require taxpayers to report certain information on Internal Revenue Service Form 8886 if they participate in a “reportable transaction.” You may be required to file this form with the IRS if we participate in a “reportable transaction.” A transaction may be a reportable transaction based upon any of several factors. You are urged to consult with your own tax advisor concerning the application of any of these factors to your investment in our common units. Congress is considering legislative proposals that, if enacted, would impose significant penalties for failure to comply with these disclosure requirements. The Treasury Regulations also impose obligations on “material advisors” that organize, manage or sell interests in registered “tax shelters.” As stated above, we have registered as a tax shelter, and, thus, one of our material advisors will be required to maintain a list with specific information, including your name and tax identification number, and to furnish this information to the IRS upon request. You are urged to consult with your own tax advisor concerning any possible disclosure obligation with respect to your investment and should be aware that we and our material advisors intend to comply with the list and disclosure requirements.

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We will treat each purchaser of units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

       Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read “Material Tax Consequences — Uniformity of Units” for a further discussion of the effect of the depreciation and amortization positions we will adopt.

 
You will likely be subject to state and local taxes and return filing requirements as a result of investing in our common units.

       In addition to federal income taxes, you will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. You will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We will initially own property and conduct business in New Mexico, Arizona, Texas, Washington, Utah, and Idaho. Of those states, only Texas and Washington do not currently impose a state income tax. We may own property or conduct business in other states or foreign countries in the future. It is your responsibility to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state and local tax consequences of an investment in our common units.

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USE OF PROCEEDS

       We expect to receive net proceeds of approximately $118.7 million from the sale of 6,000,000 common units offered by this prospectus, after deducting underwriting discounts but before paying estimated offering expenses. We base these proceeds on an assumed public offering price of $21.25 per unit.

       We intend to use the net proceeds of this offering to:

  •  make an $75.6 million cash distribution to Holly Corporation and its affiliates, in part to reimburse them for certain capital expenditures;
 
  •  repay $30.1 million of debt we owe to Holly Corporation;
 
  •  provide $10.0 million in net working capital; and
 
  •  pay $3.0 million of expenses associated with the offering and related formation transactions.

       At the closing of this offering, we will borrow $25.0 million under our credit agreement to fund an additional $25.0 million cash distribution to Holly Corporation. The $30.1 million of debt we owe to Holly Corporation is payable on demand and bears no interest. This debt was incurred in connection with the acquisition of an additional 45% interest in Rio Grande Pipeline Company and the acquisition of the Woods Cross assets.

       The proceeds from any exercise of the underwriters’ over-allotment option will be used to redeem a number of common units from Holly Corporation and its affiliates equal to the number of common units issued upon exercise of the over-allotment option at a price per common unit equal to the proceeds per common unit before expenses but after underwriting discounts and commissions.

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CAPITALIZATION

       The following table shows:

  •  our historical capitalization as of March 31, 2004; and
 
  •  our pro forma capitalization as of March 31, 2004, adjusted to reflect the offering of the common units, the borrowing under our credit agreement and the application of the net proceeds in the manner described under “Use of Proceeds.”

       This table is derived from, should be read together with and is qualified in its entirety by reference to our historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus.

                       
As of
March 31, 2004

Actual Pro Forma


(In thousands)
Debt due to affiliate
  $ 30,082     $  
Term loan under new credit agreement
          25,000  
     
     
 
 
Total debt
    30,082       25,000  
Equity:
               
 
Net parent investment
    78,480        
 
Held by public:
               
   
Common units
          115,734  
 
Held indirectly by Holly Corporation:
               
   
Common units
          (5,781 )
   
Subordinated units
          (40,464 )
   
General partner interest
          (1,651 )
     
     
 
     
Total equity
    78,480       67,838  
     
     
 
     
Total capitalization
  $ 108,562     $ 92,838  
     
     
 

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DILUTION

       Dilution is the amount by which the offering price will exceed the net tangible book value per unit after the offering. Assuming an initial public offering price of $21.25 per common unit, on a pro forma basis as of March 31, 2004, after giving effect to the offering of common units and the related transactions, our net tangible book value was $61.5 million, or $4.31 per common unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table.

                 
Assumed initial public offering price per common unit
          $ 21.25  
Pro forma net tangible book value per common unit before the offering(1)
  $ 6.82          
Decrease in net tangible book value per common unit attributable to purchasers in the offering
    (2.51 )        
     
         
Less: Pro forma net tangible book value per common unit after the offering(2)
            4.31  
             
 
Immediate dilution in net tangible book value per common unit to purchasers in the offering
          $ 16.94  
             
 


(1)  Determined by dividing the number of units (1,000,000 common units, 7,000,000 subordinated units, and the 2% general partner interest, which has a dilutive effect equivalent to 285,714 units) to be issued to the general partner and its affiliates for their contribution of assets and liabilities to us into the net tangible book value of the contributed assets and liabilities.
 
(2)  Determined by dividing the total number of units (7,000,000 common units, 7,000,000 subordinated units, and the 2% general partner interest, which has a dilutive effect equivalent to 285,714 units) to be outstanding after the offering into our pro forma net tangible book value, after giving effect to the application of the net proceeds of the offering. The general partner’s dilutive effect equivalent was determined by multiplying the total number of units deemed to be outstanding (i.e., the total number of common and subordinated units outstanding divided by 98%) by the general partner’s 2% general partner interest.

       The following table sets forth the number of units that we will issue and the total consideration contributed to us by the general partner and its affiliates in respect of their units and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus.

                                   
Units Acquired Total Consideration


Number Percent Amount Percent




(In thousands)
General partner and its affiliates (1)(2)
    8,285,714       58.0 %   $ (47,896 )     (71 )%
New investors
    6,000,000       42.0 %     115,734       171 %
     
     
     
     
 
 
Total
    14,285,714       100.0 %   $ 67,838       100.0 %
     
     
     
     
 


(1)  Upon the consummation of the transactions contemplated by this prospectus, our general partner and its affiliates will own 1,000,000 common units, 7,000,000 subordinated units, and a 2% general partner interest having a dilutive effect equivalent to 285,714 units.

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(2)  The assets contributed by the general partner and its affiliates were recorded at historical cost in accordance with accounting principles generally accepted in the United States. Book value of the consideration provided by the general partner and its affiliates, as of March 31, 2004, after giving effect to the application of the net proceeds of the offering, is as follows:
             
(In thousands)

Book value of net assets contributed
  $ 62,756  
Less: Distribution to Holly Corporation from net proceeds of the offering
    75,652  
    Distribution to Holly Corporation from borrowings under the credit agreement     25,000  
    Replenishment of net working capital     10,000  
     
 
 
Total consideration
  $ (47,896 )
     
 

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CASH DISTRIBUTION POLICY

Distributions of Available Cash

       General. Within 45 days after the end of each quarter, beginning with the quarter ending September 30, 2004, we will distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from the closing of the offering through September 30, 2004 based on the actual length of the period.

       Definition of Available Cash. We define available cash in the glossary, and it generally means, for each fiscal quarter, all cash on hand at the end of the quarter:

  •  less the amount of cash reserves established by our general partner to:

  •  provide for the proper conduct of our business;
 
  •  comply with applicable law, any of our debt instruments, or other agreements; or
 
  •  provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;

  •  plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.

       Intent to Distribute the Minimum Quarterly Distribution. We intend to distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.50 per unit, or $2.00 per year, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on the common units in any quarter, and we will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under our credit agreement. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Agreement” for a discussion of the restrictions to be included in our credit agreement that may restrict our ability to make distributions.

Operating Surplus and Capital Surplus

       General. All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” We distribute available cash from operating surplus differently than available cash from capital surplus.

       Definition of Operating Surplus. We define operating surplus in the glossary, and for any period it generally means:

  •  our cash balance on the closing date of this offering; plus
 
  •  $10.0 million (as described below); plus
 
  •  all of our cash receipts after the closing of this offering, excluding cash from borrowings that are not working capital borrowings, sales of equity and debt securities and sales or other dispositions of assets outside the ordinary course of business; plus
 
  •  working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; less

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  •  all of our operating expenditures after the closing of this offering, including the repayment of working capital borrowings, but not the repayment of other borrowings, and including maintenance capital expenditures; less
 
  •  the amount of cash reserves established by our general partner to provide funds for future operating expenditures.

       Definition of Capital Surplus. We also define capital surplus in the glossary, and it will generally be generated only by:

  •  borrowings other than working capital borrowings;
 
  •  sales of debt and equity securities; and
 
  •  sales or other disposition of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.

       Characterization of Cash Distributions. We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As reflected above, operating surplus includes $10.0 million in addition to our cash balance on the closing date of this offering, cash receipts from our operations and cash from working capital borrowings. This amount does not reflect actual cash on hand at closing that is available for distribution to our unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to $10.0 million of cash we receive in the future from non-operating sources, such as asset sales, issuances of securities, and long-term borrowings, that would otherwise be distributed as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Subordination Period

       General. During the subordination period, which we define below and in the glossary, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.50 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

       Definition of Subordination Period. We define the subordination period in the glossary. The subordination period will extend until the first day of any quarter beginning after June 30, 2009 that each of the following tests are met:

  •  distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
 
  •  the “adjusted operating surplus” (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and

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  •  there are no arrearages in payment of the minimum quarterly distribution on the common units.

       If the unitholders remove the general partner without cause, the subordination period may end before June 30, 2009.

       Definition of Adjusted Operating Surplus. We define adjusted operating surplus in the glossary and for any period it generally means:

  •  operating surplus generated with respect to that period; less
 
  •  any net increase in working capital borrowings with respect to that period; less
 
  •  any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus
 
  •  any net decrease in working capital borrowings with respect to that period; plus
 
  •  any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

       Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods.

       Effect of Expiration of the Subordination Period. Upon expiration of the subordination period, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by the general partner and its affiliates are not voted in favor of such removal:

  •  the subordination period will end and each subordinated unit will immediately convert into one common unit;
 
  •  any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
 
  •  the general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Distributions of Available Cash from Operating Surplus during the Subordination Period

       We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

  •  First, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;
 
  •  Second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;
 
  •  Third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and
 
  •  Thereafter, in the manner described in “— Incentive Distribution Rights” below.

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Distributions of Available Cash from Operating Surplus after the Subordination Period

       We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

  •  First, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and
 
  •  Thereafter, in the manner described in “— Incentive Distribution Rights” below.

Incentive Distribution Rights

       Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement.

       If for any quarter:

  •  we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and
 
  •  we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:

  •  First, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.55 per unit for that quarter (the “first target distribution”);
 
  •  Second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives a total of $0.625 per unit for that quarter (the “second target distribution”);
 
  •  Third, 75% to all unitholders, pro rata, and 25% to the general partner, until each unitholder receives a total of $0.75 per unit for that quarter (the “third target distribution”); and
 
  •  Thereafter, 50% to all unitholders, pro rata, and 50% to the general partner.

In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution. The percentage interests set forth above for our general partner include its 2% general partner interest and assume the general partner has not transferred its incentive distribution rights.

Percentage Allocations of Available Cash from Operating Surplus

       The following table illustrates the percentage allocations of the additional available cash from operating surplus between the unitholders and our general partner up to the various target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly

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distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2% general partner interest and assume the general partner has not transferred its incentive distribution rights.
                     
Total Quarterly Marginal Percentage Interest
Distribution in Distributions


Target Amount Unitholders General Partner



Minimum Quarterly Distribution
  $0.50     98 %     2 %
First Target Distribution
  up to $0.55     98 %     2 %
Second Target Distribution
  above $0.55 up to $0.625     85 %     15 %
Third Target Distribution
  above $0.625 up to $0.75     75 %     25 %
Thereafter
  above $0.75     50 %     50 %

Distributions from Capital Surplus

       How Distributions from Capital Surplus Will Be Made. We will make distributions of available cash from capital surplus, if any, in the following manner:

  •  First, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price;
 
  •  Second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and
 
  •  Thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

       Effect of a Distribution from Capital Surplus. The partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for the general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

       Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50% being paid to the holders of units and 50% to the general partner. The percentage interests shown for our general partner include its 2% general partner interest and assume the general partner has not transferred the incentive distribution rights.

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Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

       In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

  •  the minimum quarterly distribution;
 
  •  target distribution levels;
 
  •  the unrecovered initial unit price;
 
  •  the number of common units issuable during the subordination period without a unitholder vote; and
 
  •  the number of common units into which a subordinated unit is convertible.

       For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level, the number of common units issuable during the subordination period without unitholder vote would double and each subordinated unit would be convertible into two common units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

       In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental taxing authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, we will reduce the minimum quarterly distribution and the target distribution levels for each quarter by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter and the denominator of which is the sum of available cash for that quarter plus the general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

       General. If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

       The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of the general partner.

       Manner of Adjustments for Gain. The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:

  •  First, to the general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

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  •  Second, 98% to the common unitholders, pro rata, and 2% to the general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;
 
  •  Third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;
 
  •  Fourth, 98% to all unitholders, pro rata, and 2% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2% to the general partner, for each quarter of our existence;
 
  •  Fifth, 85% to all unitholders, pro rata, and 15% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to the general partner for each quarter of our existence;
 
  •  Sixth, 75% to all unitholders, pro rata, and 25% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75% to the unitholders, pro rata, and 25% to the general partner for each quarter of our existence; and
 
  •  Thereafter, 50% to all unitholders, pro rata, and 50% to the general partner.

The percentage interests set forth above for our general partner include its 2% general partner interest and assume the general partner has not transferred the incentive distribution rights.

       If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

       Manner of Adjustments for Losses. If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to the general partner and the unitholders in the following manner:

  •  First, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to the general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;
 
  •  Second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to the general partner, until the capital accounts of the common unitholders have been reduced to zero; and
 
  •  Thereafter, 100% to the general partner.

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       If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

       Adjustments to Capital Accounts. We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, we will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the general partner’s capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

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CASH AVAILABLE FOR DISTRIBUTION

       We intend to pay each quarter, to the extent we have sufficient available cash from operating surplus, the minimum quarterly distribution of $0.50 per unit, or $2.00 per year, on all the common units and subordinated units.

       The amounts of available cash from operating surplus needed to pay the minimum quarterly distribution for one quarter and for four quarters on the common units, the subordinated units, and the general partner interest to be outstanding immediately after this offering are approximately:

                   
One Quarter Four Quarters


(In thousands)
Common units
  $ 3,500.0     $ 14,000.0  
Subordinated units
    3,500.0       14,000.0  
2% general partner interest
    142.9       571.4  
     
     
 
 
Total
  $ 7,142.9     $ 28,571.4  
     
     
 

  Estimated available cash from operating surplus during 2003 would not have been sufficient to pay the minimum quarterly distribution on all units.

       If we had completed the transactions contemplated in this prospectus on January 1, 2003, pro forma available cash from operating surplus generated during 2003 would have been approximately $26.4 million. Pro forma available cash from operating surplus does not reflect any general and administrative expenses. Estimated available cash from operating surplus includes general and administrative expenses, such as cost of tax return preparation, accounting support services, annual and quarterly reports to unitholders, investor relations, directors’ and officers’ insurance and registrar and transfer agent fees, of approximately $1.7 million per year that we expect to incur as a result of being a publicly traded partnership as well as our payment to Holly Corporation of an annual fee of approximately $2.0 million for certain other general and administrative services pursuant to the omnibus agreement. Our estimated available cash from operating surplus generated during 2003 would have been approximately $22.7 million. This amount would have been sufficient to allow us to pay the full minimum quarterly distribution on the common units and approximately 58.7% of the minimum quarterly distribution on the subordinated units for that period. If we had completed the transactions contemplated in this prospectus on January 1, 2004, pro forma available cash from operating surplus generated during the three months ended March 31, 2004 would have been approximately $8.6 million and estimated available cash from operating surplus would have been approximately $7.6 million. This amount would have been sufficient to allow us to pay the full minimum quarterly distribution on all of the units for the three months ended March 31, 2004.

       We derived the amounts of pro forma available cash from operating surplus from our pro forma financial statements. The pro forma financial statements do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. Furthermore, available cash from operating surplus as defined in the partnership agreement is a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. A more complete explanation of the pro forma adjustments can be found in the Notes to Pro Forma Financial Statements. We derived the amounts of estimated available cash from operating surplus shown above in the manner described in Appendix D. As a result, the amount of estimated available cash from operating surplus should only be viewed as a general indication of the amount of available cash from operating surplus that we might have generated had we been formed in earlier periods.

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  We believe we will have sufficient cash from operating surplus following the offering to pay the minimum quarterly distribution on all units through June 30, 2005.

       We believe that, following completion of the offering, we will have sufficient available cash from operating surplus to allow us to make the full minimum quarterly distribution on all the outstanding units for each quarter through June 30, 2005. Our belief is based on a number of specific assumptions, including the assumptions that:

  •  average quarterly volumes shipped on our pipelines will be no less than the 65,300 bpd shipped during the three months ended March 31, 2004;
 
  •  there will be no turnaround at the Navajo Refinery during the twelve months ended June 30, 2005;
 
  •  average quarterly revenues for our terminals will be no less than the $3.0 million we received from the terminals during the three months ended March 31, 2004;
 
  •  we will realize the pipeline tariffs and terminal fees provided in our pipelines and terminals agreement with Holly Corporation;
 
  •  our maintenance capital expenditures for the twelve months ended June 30, 2005 will be approximately $1.5 million;
 
  •  general and administrative expenses for the twelve months ended June 30, 2005 will be approximately $3.7 million;
 
  •  operating expenses will increase by approximately $2.0 million for the twelve months ended June 30, 2005 compared to the operating expenses we incurred in 2003 due to additional operating expenses associated with the Rio Grande pipeline and the Spokane, Boise and Burley terminals and the Woods Cross truck rack;
 
  •  no material accidents, releases, unscheduled downtime, or similar unanticipated and material events will occur; and
 
  •  market, regulatory, and overall economic conditions will not change substantially.

       While we believe that these assumptions are reasonable in light of management’s current beliefs concerning future events, the assumptions underlying the projections are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions are not realized, the actual available cash from operating surplus that we could generate could be substantially less than that currently expected and could, therefore, be insufficient to permit us to make the full minimum quarterly distribution on all units, in which event the market price of the common units may decline materially. When reading this section, you should keep in mind the risk factors and other cautionary statements under the heading “Risk Factors” and elsewhere in this prospectus.

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SELECTED HISTORICAL AND OPERATING DATA OF

NAVAJO PIPELINE CO., L.P. (PREDECESSOR)
AND PRO FORMA FINANCIAL DATA OF
HOLLY ENERGY PARTNERS, L.P. (SUCCESSOR)

       The following table sets forth selected historical financial and operating data of Navajo Pipeline Co., L.P. (Predecessor), the predecessor to Holly Energy Partners, L.P., and pro forma financial data of Holly Energy Partners, L.P., in each case for the periods and as of the dates indicated.

       Historical Results. The selected historical financial data for our predecessor for 2001, 2002 and 2003 are derived from the audited consolidated combined financial statements of Navajo Pipeline Co., L.P. (Predecessor) that are included in this prospectus. The selected historical financial data for our predecessor for 1999 and 2000 are derived from the unaudited consolidated combined financial statements of Navajo Pipeline Co., L.P. (Predecessor). The selected historical financial data for our predecessor for the three months ended March 31, 2003 and 2004 are derived from the unaudited consolidated combined financial statements of Navajo Pipeline Co., L.P. (Predecessor) that are included in this prospectus. In reviewing this data, you should be aware of the following.

       Until January 1, 2004, our historical revenues included only actual amounts received by the predecessor from:

  •  third parties who utilized our pipelines and terminals;
 
  •  Holly Corporation for use of our FERC-regulated refined product pipeline; and
 
  •  Holly Corporation for use of the Lovington crude oil pipelines, which are not being contributed to our partnership.

       Until January 1, 2004, we did not record revenue for:

  •  transporting products for Holly Corporation on our intrastate refined product pipelines;
 
  •  providing terminalling services to Holly Corporation; and
 
  •  transporting crude oil and feedstocks on two intermediate product pipelines that connect Holly Corporation’s Artesia and Lovington facilities, which are not being contributed to our partnership.

       In addition, our historical results of operations reflect the impact of the following acquisitions completed in June 2003:

  •  the purchase of an additional 45% interest in the Rio Grande Pipeline Company on June 30, 2003, bringing our total ownership to 70%, which resulted in our consolidating the Rio Grande Pipeline Company from the date of this acquisition rather than accounting for it on the equity method; and
 
  •  the purchase of terminals in Spokane, Washington, and Boise and Burley, Idaho, as well as the Woods Cross truck rack, all of which are related to the Woods Cross Refinery.

       Furthermore, the historical financial data do not reflect any general and administrative expenses as Holly Corporation has not historically allocated any of its general and administrative expenses to its pipelines and terminals. Our historical results of operations include costs associated with crude oil and intermediate product pipelines, which are not being contributed to our partnership.

       Pro Forma Results. The selected pro forma financial data presented below as of March 31, 2004 and for the year ended December 31, 2003 and the three months ended March 31, 2004

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are derived from the pro forma financial statements that are included in this prospectus. The pro forma financial data give pro forma effect to:

  •  the transfer of certain of our predecessor’s operations to Holly Energy Partners, L.P.;
 
  •  the consolidation of the Rio Grande Pipeline Company as if the additional 45% interest had been acquired as of January 1, 2003;
 
  •  the execution of the pipelines and terminals agreement; and
 
  •  the related transactions in connection with the closing of this offering.

       The pro forma balance sheet assumes that the offering and the related transactions occurred as of March 31, 2004 and the pro forma statements of income assume that the offering and the related transactions occurred as of January 1, 2003.

       The pro forma financial data for the year ended December 31, 2003 reflect the revenues that would have been recorded in 2003, using historical volumes, if the initial tariff rates and terminalling fees in the pipelines and terminals agreement had been in effect for the entire year. Because we began charging Holly Corporation fees at the rates set forth in the pipelines and terminals agreement for the use of all of our pipelines and terminals commencing January 1, 2004, the pro forma financial data for the three months ended March 31, 2004 reflect actual revenues received from Holly Corporation. We believe that our pipeline tariffs and terminalling fees are comparable to those that would be charged by third parties in the specific marketing locations. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Impact of Pipelines and Terminals Agreement.”

       The pro forma financial data do not reflect either the $2.0 million administrative fee that Holly Corporation will charge us under the omnibus agreement or the estimated $1.7 million in additional general and administrative expenses we expect to incur as a result of being a separate public entity.

 
Non-GAAP and Other Financial Information

       The following table presents a non-GAAP financial measure: earnings before interest, taxes, depreciation and amortization, or EBITDA, which we use in our business. We explain this measure below and reconcile it to net income and cash flow from operating activities, our most directly comparable financial measures calculated and presented in accordance with GAAP.

       Maintenance capital expenditures represent capital expenditures to replace partially or fully depreciated assets to maintain the operating capacity of existing assets and extend their useful lives. Expansion capital expenditures represent capital expenditures to expand the operating capacity of existing or new assets, whether through construction or acquisition. Repair and maintenance expenses associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred.

       Use of the term “throughput” in this prospectus generally refers to the refined product barrels that pass through each pipeline or terminal facility, even if those barrels are transported or pass through another of our pipeline or terminal facilities, for which we receive either pipeline tariff or terminal service fee revenue.

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       The following table should be read together with, and is qualified in its entirety by reference to, the historical and unaudited pro forma financial statements and the accompanying notes included elsewhere in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

                                                                             
Holly Energy Partners, L.P.

Navajo Pipeline Co., L.P. (Predecessor)

Pro Forma

Three Months Three Months
Ended Year Ended Ended
Years Ended December 31, March 31, December 31, March 31,




1999 2000 2001 2002 2003 2003 2004 2003 2004









(In thousands, except per unit data)
STATEMENT OF INCOME DATA:
                                                                       
Revenue
  $ 16,774     $ 22,878     $ 20,647     $ 23,581     $ 30,800     $ 5,662     $ 18,771     $ 52,707     $ 15,432  
Operating costs and expenses
                                                                       
 
Operations
    13,822       17,505       17,388       19,442       24,193       5,166       6,452       21,550       5,228  
 
Selling, general and administrative
                                                       
 
Depreciation and amortization
    2,491       4,940       3,740       4,475       6,453       1,179       2,046       6,928       1,834  
     
     
     
     
     
     
     
     
     
 
   
Total operating costs and expenses
    16,313       22,445       21,128       23,917       30,646       6,345       8,498       28,478       7,062  
     
     
     
     
     
     
     
     
     
 
Operating income (loss)
    461       433       (481 )     (336 )     154       (683 )     10,273       24,229       8,370  
Interest expense
                                              (1,750 )     (437 )
Equity income from Rio Grande Pipeline Company
    2,606       1,010       2,284       2,737       894       285                    
Interest and other income
    435       657       620       269       291       37       35       308       35  
     
     
     
     
     
     
     
     
     
 
      3,041       1,667       2,904       3,006       1,185       322       35       (1,442 )     (402 )
     
     
     
     
     
     
     
     
     
 
Income before minority interest
    3,502       2,100       2,423       2,670       1,339       (361 )     10,308       22,787       7,968  
Minority interest in Rio Grande Pipeline Company
                            (758 )           (688 )     (1,405 )     (688 )
     
     
     
     
     
     
     
     
     
 
Net income
  $ 3,502     $ 2,100     $ 2,423     $ 2,670     $ 581     $ (361 )   $ 9,620     $ 21,382     $ 7,280  
     
     
     
     
     
     
     
     
     
 
Pro forma net income per limited partner unit
                                                          $ 1.50     $ 0.51  
                                                             
     
 

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Holly Energy Partners, L.P.

Navajo Pipeline Co., L.P. (Predecessor)

Pro Forma

Three Months Three Months
Ended Year Ended Ended
Years Ended December 31, March 31, December 31, March 31,




1999 2000 2001 2002 2003 2003 2004 2003 2004









(In thousands, except per unit data)
OTHER FINANCIAL DATA:
                                                                       
EBITDA
  $ 5,558     $ 6,383     $ 5,543     $ 6,876     $ 6,743     $ 781     $ 11,631     $ 29,752     $ 9,516  
     
     
     
     
     
     
     
     
     
 
Cash flows from operating activities
  $ 15,848     $ 1,600     $ 10,273     $ 4,271     $ 5,909     $ 187     $ 283                  
     
     
     
     
     
     
     
                 
Cash flows from investment activities
  $ (15,848 )   $ (1,600 )   $ (10,273 )   $ (4,271 )   $ (29,297 )   $ (187 )   $ (2,599 )                
     
     
     
     
     
     
     
                 
Cash flows from financing activities
  $     $     $     $     $ 30,082     $     $                  
     
     
     
     
     
     
     
                 
Maintenance capital expenditures
  $ 1,153     $ 1,179     $ 760     $ 1,178     $ 1,934     $ 187     $ 558                  
Expansion capital expenditures
    14,695       3,699       10,756       5,581       4,837     $     $ 991                  
     
     
     
     
     
     
     
                 
Total capital expenditures
  $ 15,848     $ 4,878     $ 11,516     $ 6,759     $ 6,771     $ 187     $ 1,549                  
     
     
     
     
     
     
     
                 
OPERATING DATA (bbls):
                                                                       
Refined product pipeline throughput
    21,898       24,400       21,992       25,127       23,978       5,904       7,095                  
Refined product terminal throughput
    27,851       33,506       30,302       34,435       40,147       7,791       12,866                  
BALANCE SHEET DATA (at period end):
                                                                       
Net property, plant and equipment
  $ 52,227     $ 50,230     $ 57,801     $ 60,073     $ 95,826     $ 58,930     $ 95,890             $ 81,927  
Total assets
    65,797       70,908       84,282       88,338       140,425       89,296       147,588               130,286  
Total liabilities
    6,871       7,722       18,674       20,059       57,889       21,377       54,994               48,334  
Net partners’ investment
    58,926       63,186       65,609       68,279       68,860       67,920       78,480               67,838  

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Non-GAAP Financial Measure

       For a discussion of the non-GAAP financial measure of EBITDA, please read “Summary — Summary Historical and Operating Data and Pro Forma Financial Data — Non-GAAP and Other Financial Information” beginning on page 15. The following table presents a reconciliation of EBITDA to the most directly comparable GAAP financial measures, on a historical basis and pro forma basis, as applicable, for each of the years indicated.

                                                                             
Holly Energy Partners, L.P.

Navajo Pipeline Co., L.P. (Predecessor)

Pro Forma

Three Months Three Months
Ended Year Ended Ended
Years Ended December 31, March 31, December 31, March 31,




1999 2000 2001 2002 2003 2003 2004 2003 2004









(In thousands)
Reconciliation of EBITDA to net income:
                                                                       
 
Net income
  $ 3,502     $ 2,100     $ 2,423     $ 2,670     $ 581     $ (361 )   $ 9,620     $ 21,382     $ 7,280  
 
Add
                                                                       
   
Depreciation and amortization
    2,491       4,940       3,740       4,475       6,453       1,179       2,046       6,928       1,834  
   
Interest expense
                                              1,750       437  
     
     
     
     
     
     
     
     
     
 
      5,993       7,040       6,163       7,145       7,034       818       11,666       30,060       9,551  
 
Less
                                                                       
   
Interest income
    435       657       620       269       291       37       35       308       35  
     
     
     
     
     
     
     
     
     
 
EBITDA
  $ 5,558     $ 6,383     $ 5,543     $ 6,876     $ 6,743     $ 781     $ 11,631     $ 29,752     $ 9,516  
     
     
     
     
     
     
     
     
     
 
Reconciliation of EBITDA to cash flows from operating activities:
                                                                       
 
Cash flow from operating activities
  $ 15,848     $ 1,600     $ 10,273     $ 4,271     $ 5,909     $ 187     $ 283                  
 
Add
                                                                       
   
Interest income
    (435 )     (657 )     (620 )     (269 )     (291 )     (37 )     (35 )                
   
Equity in earnings of Rio Grande Pipeline Company
    2,606       1,010       2,284       2,737       894       285                        
   
Minority interest
                            (758 )           (688 )                
   
Increase (decrease) in working capital
    (12,461 )     4,430       (6,394 )     137       989       346       12,071                  
     
     
     
     
     
     
     
                 
EBITDA
  $ 5,558     $ 6,383     $ 5,543     $ 6,876     $ 6,743     $ 781     $ 11,631                  
     
     
     
     
     
     
     
                 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

       You should read the following discussion of the financial condition and results of operations of Navajo Pipeline Co., L.P. (Predecessor) in conjunction with the historical combined financial statements of Navajo Pipeline Co., L.P. (Predecessor) and the pro forma financial statements of Holly Energy Partners included elsewhere in this prospectus. Among other things, those historical and pro forma financial statements include more detailed information regarding the basis of presentation for the following information.

Overview

 
General

       Our pipelines transport light refined products (gasoline, diesel and jet fuel) from Holly Corporation’s Navajo Refinery in New Mexico to its customers in the metropolitan and rural areas of Texas, New Mexico, Arizona, Colorado, Utah and northern Mexico. We also transport gasoline and diesel fuel for Alon USA LP from Orla, Texas to El Paso, Texas under three separate long-term capacity lease agreements. Our assets also include a 70% interest in Rio Grande Pipeline Company, a joint venture that owns an LPG pipeline located in West Texas; nine refined product terminals; a refined product truck rack located within the Artesia Refinery, which is held pursuant to a long-term ground lease; and a refined product truck rack located within the Woods Cross Refinery. We own a 100% interest in five of these terminals and the truck racks and a 50% interest in four of these terminals. The substantial majority of our business is devoted to providing transportation and terminalling services to Holly Corporation. Holly Corporation accounted for approximately 57.3% of our pro forma revenues for the year ended December 31, 2003 and 59.6% of our pro forma revenues for the three months ended March 31, 2004.

Historical Results of Operations

       In reviewing our historical results of operations that are discussed below, you should be aware of the following:

       Until January 1, 2004, our historical revenues included only actual amounts received from:

  •  third parties who utilized our pipelines and terminals;
 
  •  Holly Corporation for use of our FERC-regulated refined product pipeline; and
 
  •  Holly Corporation for use of the Lovington crude oil pipelines, which are not being contributed to our partnership.

       Until January 1, 2004, we did not record revenue for:

  •  transporting products for Holly Corporation on our intrastate refined product pipelines;
 
  •  providing terminalling services to Holly Corporation; and
 
  •  transporting crude oil and feedstocks on two intermediate product pipelines that connect Holly Corporation’s Artesia and Lovington facilities, which are not being contributed to our partnership.

       Commencing January 1, 2004, we began charging Holly Corporation fees for the use of all of our pipelines and terminals at the rates set forth in the pipelines and terminals agreement.

       In addition, our historical results of operations reflect the impact of the following acquisitions completed in June 2003:

  •  the purchase of an additional 45% interest in the Rio Grande Pipeline Company on June 30, 2003, bringing our total ownership to 70%, which resulted in our consolidating

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  the Rio Grande Pipeline Company from the date of this acquisition rather than accounting for it on the equity method; and
 
  •  the purchase of terminals in Spokane, Washington, and Boise and Burley, Idaho, as well as the Woods Cross truck rack, all of which are related to the Woods Cross Refinery.

       Furthermore, the historical financial data do not reflect any general and administrative expenses as Holly Corporation has not historically allocated any of its general and administrative expenses to its pipelines and terminals. Our historical results of operations include costs associated with crude oil and intermediate product pipelines, which are not being contributed to our partnership.

       While we do not discuss our pro forma financial statements below, these statements, and the assumptions made therein, are presented in the financial statements included elsewhere in this prospectus. You should review our pro forma financials to more fully understand the impact that this offering and the related transactions will have on our results of operations. Most importantly, the pro forma financial data give pro forma effect to:

  •  the transfer of certain of our predecessor’s operations to Holly Energy Partners, L.P.;
 
  •  the consolidation of the Rio Grande Pipeline Company as if the additional 45% interest had been acquired as of January 1, 2003;
 
  •  the execution of the pipelines and terminals agreement and the recognition of revenues derived therefrom; and
 
  •  the related transactions in connection with the closing of this offering.

Nature of Revenues and Throughput

       The amount of revenue we generate will primarily depend on the level of our tariffs and terminal service fees and the amount of throughput in our pipelines and terminals. When transporting barrels on our pipelines, we charge a tariff based on the point of origin and the ultimate destination. For example, on our Artesia, New Mexico to Moriarty, New Mexico to Bloomfield, New Mexico pipeline segment, we have separate tariffs depending on whether the ultimate destination from Artesia is Moriarty or Bloomfield.

       We generate terminal revenue by charging fees for refined products that are transported through our terminals. The operating income that is generated by our terminalling operations depends on throughput volumes and the level of fees charged for terminal services as well as the fixed and variable costs of operating the terminals. Terminalling fees are not directly affected by the absolute price level of refined products, although they are affected by the absolute levels of supply and demand for these products. Our terminal fees are not regulated by any governmental authority.

       Our operating expenses include compensation and related employee benefits, maintenance and operating supplies, rental expenses on our leased pipeline and contract services, all of which are relatively fixed costs. Operating expenses also include energy and drag reducing agents, both of which vary with the quantities transported on our pipelines.

       The refined product throughput in our pipelines and terminals is directly affected by the level of supply and demand for refined products in the markets served directly or indirectly by our assets. Although the demand for gasoline in most markets peaks during the summer driving season, which extends from April to September, and declines during the fall and winter months, the throughput in our systems is not materially affected by seasonality.

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Agreements with Holly Corporation

       Under a 15 year pipelines and terminals agreement we will enter into with Holly Corporation concurrently with the closing of this offering, Holly Corporation will pay us fees to transport on our refined product pipelines or throughput in our terminals a volume of refined products that will produce at least $35.4 million of revenue in the first year. This minimum revenue commitment will increase each year at a rate equal to the percentage change in the producer price index, but will not decrease as a result of a decrease in the producer price index. Holly Corporation will pay the published tariff rates on the pipelines and contractually agreed upon fees at the terminals. The tariffs will adjust annually at a rate equal to the percentage change in the producer price index. The terminal fees will adjust annually based upon an index comprised of comparable fees posted by a third party. Holly Corporation’s minimum revenue commitment will apply only to our initial assets and may not be spread among assets we subsequently acquire. If Holly Corporation fails to meet its minimum revenue commitment in any quarter, it will be required to pay us in cash the amount of any shortfall by the last day of the month following the end of the quarter. A shortfall payment may be applied as a credit in the following four quarters after Holly Corporation’s minimum obligations are met.

       Furthermore, if new laws or regulations that affect terminals or pipelines generally are enacted that require us to make substantial and unanticipated capital expenditures at the pipelines or terminals, we will have the right to negotiate a monthly surcharge on Holly Corporation for the use of the terminals or to file for an increased tariff rate for use of the pipelines to cover Holly Corporation’s pro rata portion of the cost of complying with these laws or regulations, after we have made efforts to mitigate their effect. We and Holly Corporation will negotiate in good faith to agree on the level of the monthly surcharge or increased tariff rate.

       Holly Corporation’s obligations under this agreement may be proportionately reduced or suspended if Holly Corporation shuts down or materially reconfigures one of its refineries. Holly Corporation will be required to give at least twelve months’ advance notice of any long-term shut-down or material reconfiguration. Holly Corporation’s obligations may also be temporarily suspended or terminated in certain circumstances. From time to time Holly Corporation considers changes to its refineries. Those changes may involve new facilities, reduction in certain operations or modifications of facilities or operations. Changes may be considered to meet market demands, to satisfy regulatory requirements or environmental and safety objectives, to improve operational efficiency or for other reasons. Holly Corporation has advised us that it currently does not intend to close or dispose of the refineries currently served by our pipelines and terminals or to cause any changes that would have a material adverse effect on these refineries’ operations. Holly Corporation is, however, actively managing its assets and operations, and, therefore, changes of some nature, possibly material to us, are likely to occur at some point in the future.

       Pursuant to the terms of the pipelines and terminals agreement, Holly Corporation has agreed to maintain commercially reasonable business interruption insurance for the benefit of its refinery assets as well as our pipelines and terminals. We reimburse Holly Corporation for the costs associated with our portion of this insurance. To the extent that Holly Corporation receives benefits under this policy, Holly Corporation has agreed to apply a portion of such amounts to the extent necessary to satisfy its minimum revenue commitment under the pipelines and terminals agreement. Allocation of business interruption insurance proceeds will be proportionate to the loss in earnings before interest, taxes, depreciation and amortization, or EBITDA, sustained by Holly Corporation and our partnership as a result of the interruption. Please read “Business — Our Relationship with Holly Corporation — Pipelines and Terminals Agreement” for a more complete description of the pipelines and terminals agreement.

       Historically, Holly Corporation has not allocated any of its general and administrative expenses to its pipeline and terminalling operations. Under an omnibus agreement with Holly

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Corporation, we will pay Holly Corporation an annual administrative fee, initially in the amount of $2.0 million, for the provision by Holly Corporation or its affiliates of various general and administrative services to us for three years following this offering. For each of the following two years, the fee may be increased by no more than the greater of 5% or the percentage increase in the consumer price index for the applicable year. In addition, our general partner will have the right to agree to further increases in connection with expansions of our operations through the acquisition or construction of new assets or businesses with the concurrence of our conflicts committee. The $2.0 million fee includes expenses incurred by Holly Corporation and its affiliates to perform centralized corporate functions, such as legal, accounting, treasury, information technology and other corporate services, including the administration of employee benefit plans. This fee does not include the salaries of pipeline and terminal personnel or other employees of Holly Logistic Services, L.L.C. or the cost of their employee benefits, such as 401(k), pension and health insurance benefits. We will also reimburse Holly Corporation and its affiliates for direct expenses they incur on our behalf. In addition, we anticipate incurring additional general and administrative costs, including costs for tax return preparation, annual and quarterly reports to unitholders, investor relations, registrar and transfer agent fees, directors’ and officers’ insurance and other costs related to operating as a separate public entity. We estimate these additional costs, which are not included in our historical costs, will be approximately $1.7 million per year.

Results of Operations

       Our results of operations are most directly impacted by production at the Navajo Refinery. The following table sets forth the barrels per day of refined products produced by the Navajo Refinery and the barrels per day of light refined products shipped on our pipelines in each of the periods presented.

                                                 
Three Months
Year Ended December 31, Ended

March 31,
1999 2000 2001 2002 2003 2004






Barrels of light refined product produced
    57,700       60,014       50,663       57,173       54,531       69,451  
Barrels of light refined products shipped
    51,365       55,825       47,364       55,288       51,456       65,313  

       Production at the Navajo Refinery in 2001 was reduced by a planned refinery turnaround and by unusual operational difficulties. Production of refined products in 2002 increased due to an increased number of production days and as Holly Corporation rebuilt inventories after the turnaround in 2001 in response to market demand for its refined products. Production of refined products in 2003 was reduced by a planned turnaround timed to coordinate with downtime required for the integration of the $85 million refinery expansion and upgrade project. Holly Corporation’s next planned turnaround at the Navajo Refinery is scheduled for 2007.

 
Historical revenue recognition policy

       The only revenues reflected in the historical financial data prior to January 1, 2004 are from (i) third parties who used our pipelines and terminals, (ii) Holly Corporation’s use of our FERC-regulated refined product pipeline and (iii) Holly Corporation’s use of the Lovington crude pipelines, which will not be contributed to Holly Energy Partners. Prior to January 1, 2004, Holly Corporation was not charged fees for services rendered on non-FERC regulated pipelines or on any terminal facilities. Commencing January 1, 2004, Holly Corporation began to be charged for all services rendered utilizing our pipeline and terminal facilities, at rates established by the pipelines and terminals agreement.

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       The following table sets forth historical revenues recognized and related product volume information. Historical information is presented for the Lovington crude oil pipelines and the intermediate product pipelines connecting Holly Corporation’s Artesia and Lovington facilities because they were owned by Navajo Pipeline Company, L.P. (Predecessor). Revenues for Rio Grande Pipeline Company are presented only from June 30, 2003, the date we increased our ownership interest from 25% to 70%.

                                             
Year Ended December 31,

1999 2000 2001 2002 2003





(dollars in thousands,
except tariffs and service fees)
Revenues
                                       
 
Refined Product Pipelines
                                       
   
Artesia to Orla to El Paso pipeline
  $ 15,754     $ 16,204     $ 15,333     $ 17,160     $ 16,273  
   
All other pipelines
                             
     
     
     
     
     
 
      15,754       16,204       15,333       17,160       16,273  
     
     
     
     
     
 
 
Rio Grande Pipeline
                                       
   
Company
                            6,910  
     
     
     
     
     
 
 
Refined Product Terminals
                                       
   
Third party revenues
    1,020       1,544       1,730       1,645       2,680  
   
All other terminals
                             
     
     
     
     
     
 
      1,020       1,544       1,730       1,645       2,680  
 
Crude Oil and Intermediate Product Pipelines
                                       
   
Lovington crude oil pipelines
          5,130       3,584       4,776       4,937  
   
Intermediate pipelines
                             
     
     
     
     
     
 
            5,130       3,583       4,776       4,937  
     
     
     
     
     
 
    $ 16,774     $ 22,878     $ 20,647     $ 23,581     $ 30,800  
     
     
     
     
     
 
Volumes (mbbls)
                                       
 
Refined Product Pipelines
                                       
   
Artesia to Orla to El Paso pipeline
    15,566       15,917       14,391       15,320       14,658  
   
All other pipelines(1)
    6,332       8,483       7,601       9,807       9,320  
     
     
     
     
     
 
      21,898       24,400       21,992       25,127       23,978  
 
Refined Product Terminals
                                       
   
Third-party volumes
    4,903       6,064       7,414       8,148       11,232  
   
Holly Corporation volumes
    22,948       27,443       22,888       26,287       28,915  
     
     
     
     
     
 
      27,851       33,507       30,302       34,435       40,147  
     
     
     
     
     
 
Total Refined Products
    49,749       57,907       52,294       59,562       64,125  
Crude Oil and Intermediate Product Pipelines
                                       
 
Lovington crude oil pipelines
          5,130       3,583       4,776       4,937  
 
Intermediate product pipelines
    13,271       15,052       12,307       14,710       14,531  
     
     
     
     
     
 
Total
    63,020       78,089       68,184       79,048       83,593  
     
     
     
     
     
 
Average tariffs/ service fees per barrel
                                       
 
Pipelines(1)
  $ 0.45     $ 0.37     $ 0.41     $ 0.41     $ 0.41  
     
     
     
     
     
 
 
Terminals
  $ 0.04     $ 0.05     $ 0.06     $ 0.05     $ 0.07  
     
     
     
     
     
 


(1)  Excludes the Rio Grande pipeline.

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Three Months Ended March 31, 2004 Versus Three Months Ended March 31, 2003

       Revenues increased by $13.1 million from $5.7 million for the three months ended March 31, 2003 to $18.8 million for the three months ended March 31, 2004. Commencing January 1, 2004, revenues related to all intercompany and intracompany utilization of refined and intermediate product pipelines and terminals have been recorded. For the three months ended March 31, 2004 these revenues amounted to $8.0 million. In addition, revenues for the three months ended March 31, 2004 include third party revenues of $0.3 million at our Spokane terminal, which we acquired in June 2003, and $3.8 million from third parties utilizing the Rio Grande pipeline, reflecting our increased ownership interest in the Rio Grande Pipeline Company which we began consolidating on June 30, 2003. Refined products shipped on our three refined product pipelines serving the Navajo Refinery increased from 51,200 bpd in the three months ended March 31, 2003 to 65,300 bpd in the three months ended March 31, 2004 increasing pipeline revenues by approximately $0.7 million. Other revenues increased by approximately $0.3 million.

       Operating costs increased by $1.3 million from $5.2 million for the three months ended March 31, 2003 to $6.5 million for the three months ended March 31, 2004. Operating costs for the Burley, Boise and Spokane terminals we acquired in June 2003 accounted for approximately $0.4 million in the three months ended March 31, 2004 and operating expenses for the Rio Grande Pipeline Company were approximately $0.6 million. Operating expenses of the other pipeline and terminal facilities for the three months ended March 31, 2004 increased by approximately $0.4 million as a result of additional maintenance expenses on the Lovington crude system that is not being contributed to our partnership.

       Depreciation expense increased from $1.2 million for the three months ended March 31, 2003 to $2.0 million for the three months ended March 31, 2004 primarily as a result of the consolidation of Rio Grande Pipeline Company. Depreciation expense for Rio Grande Pipeline Company for the three months ended March 31, 2004 was approximately $0.8 million. Depreciation on other assets did not change materially.

 
Year Ended December 31, 2003 Versus Year Ended December 31, 2002

       Revenues increased by $7.2 million from $23.6 million for the year ended December 31, 2002 to $30.8 million for the year ended December 31, 2003, primarily as a result of the consolidation of Rio Grande Pipeline Company on June 30, 2003, when we increased our ownership interest from 25% to 70%. During the six months ended June 30, 2003, Rio Grande had been accounted for by the equity method, contributing $0.9 million to net income but no revenues. Rio Grande Pipeline Company’s revenues for the six months of 2003 that it was consolidated were $6.9 million from a third party. Pipeline revenues received from Holly Corporation decreased by $0.9 million as a result of lower volumes of light products produced at the Navajo Refinery. Third party terminal revenues increased by $1.0 million in 2003, largely as a result of the acquisition of the Spokane terminal in June 2003, which contributed third party revenues of $0.9 million in 2003.

       Operating costs increased by $4.8 million from $19.4 million for the year ended December 31, 2002 to $24.2 million for the year ended December 31, 2003. The consolidation of Rio Grande Pipeline Company and acquisition of the Spokane, Burley and Boise terminals and the Woods Cross truck rack accounted for $1.3 million and $0.9 million, respectively, of the increased costs. Operating costs for the pipelines increased $1.0 million in 2003 as compared to 2002 primarily due to a $2.2 million increase in operating costs related to the Lovington crude pipelines, reflecting increased pipeline integrity testing and related maintenance expense. The Lovington crude pipelines are not being contributed to our partnership. Operating costs for terminal facilities decreased $0.3 million in 2003 as compared to 2002, excluding the impact of new assets acquired during the year. Property taxes and insurance increased by $0.4 million in 2003 as compared to 2002.

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       Depreciation expense increased $2.0 million from $4.5 million for the year ended December 31, 2002 to $6.5 million for the year ended December 31, 2003, primarily as a result of the consolidation of Rio Grande Pipeline Company and, to a lesser extent, additional capital expenditures.

 
Year Ended December 31, 2002 Versus Year Ended December 31, 2001

       Revenues increased by $3.0 million from $20.6 million for the year ended December 31, 2001 to $23.6 million for the year ended December 31, 2002. Pipeline revenues received from Holly Corporation increased by $2.0 million in 2002 as a result of increased volumes shipped due to increased production at the Navajo Refinery. Contract revenues from Alon increased by $1.1 million in 2002 as a result of the inclusion of a full year’s revenue from the third capacity lease agreement. In addition, revenues from terminals decreased by $0.1 million as a result of lower volumes handled at our terminal in Mountain Home, Idaho.

       Operating costs increased by $2.0 million from $17.4 million for the year ended December 31, 2001 to $19.4 million for the year ended December 31, 2002. Approximately $1.2 million of the increased operating costs related to maintenance cost of the Lovington crude pipelines and approximately $0.5 million of the increased operating costs were associated with our Moriarty terminal, as a result of increased security costs and one-time expenses associated with the handling of transmix at the start-up of the terminal.

       Depreciation expense increased by $0.8 million from $3.7 million for the year ended December 31, 2001 to $4.5 million for the year ended December 31, 2002 primarily as a result of $5.2 million of capital expenditures related to the Lovington crude pipelines and $8.1 million of capital expenditures related to the new terminal facilities in Moriarty and Bloomfield, New Mexico that were made in 2001 and 2002.

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Impact of Pipelines and Terminals Agreement

       The following table displays the revenues that would have been recorded for the years 1999 through 2003 using historical volumes and as if the initial tariff rates and terminalling fees in the pipelines and terminals agreement had been in place for all periods presented. The data for 2003 includes (1) results of operations for the Boise, Burley and Spokane terminals and the Woods Cross truck rack from June 1, 2003, the date of acquisition and (2) revenues for the Rio Grande Pipeline Company from June 30, 2003, the date we increased our ownership from 25% to 70%.

                                           
Year Ended December 31,

1999 2000 2001 2002 2003





(dollars in thousands except tariffs
and service fees)
Revenues
                                       
 
Product pipelines
  $ 21,546     $ 27,170     $ 25,837     $ 30,516     $ 29,275  
 
Terminals
    5,607       7,160       6,821       7,442       9,931  
     
     
     
     
     
 
      27,153       34,330       32,658       37,958       39,206  
     
     
     
     
     
 
 
Rio Grande Pipeline Company
                            6,910  
     
     
     
     
     
 
    $ 27,153     $ 34,330     $ 32,658     $ 37,958     $ 46,116  
     
     
     
     
     
 
Volumes (mbbls)
                                       
 
Product pipelines(1)
    21,898       24,400       21,992       25,127       23,978  
 
Terminals
    27,851       33,506       30,302       34,435       40,147  
     
     
     
     
     
 
      49,749       57,906       52,294       59,562       64,125  
     
     
     
     
     
 
Average tariffs/service fees per barrel
                                       
 
Product pipelines(1)
  $ 0.98     $ 1.11     $ 1.17     $ 1.21     $ 1.22  
     
     
     
     
     
 
 
Terminals
  $ 0.20     $ 0.21     $ 0.23     $ 0.22     $ 0.25  
     
     
     
     
     
 


(1)  Excludes the Rio Grande pipeline.

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       The following table reflects the overall impact to 2003 revenues of the new tariff and terminal service fee revenues using historical throughput barrels, including the impact, if any, on each of our pipeline and terminal facilities. The amounts in the table below were calculated using historical throughput barrels. As adjusted revenues are unaudited.

                             
Year Ended December 31, 2003

Historical As Adjusted Increase
Revenues Revenues (Decrease)



(In thousands)
Refined Product Pipelines
                       
 
6” Artesia to El Paso
  $     $ 3,595     $ 3,595  
 
8”-12”-8” Artesia to Orla to El Paso
    16,273       16,273        
 
Four Corners Pipeline(1)
          9,407       9,407  
     
     
     
 
   
Total Refined Product Pipelines
    16,273       29,275       13,002  
     
     
     
 
Refined Product Terminals
                       
 
El Paso Terminal
    737       2,983       2,246  
 
Mountain Home Terminal
    482       482        
 
Moriarty Terminal
          947       947  
 
Bloomfield Terminal
          652       652  
 
Tucson Terminal
    603       1,472       869  
 
Albuquerque Terminal
          947       947  
 
Boise Terminal
          104       104  
 
Burley Terminal
          154       154  
 
Spokane Terminal
    858       897       39  
 
Artesia Truck Rack
          439       439  
 
Woods Cross Truck Rack
          854       854  
     
     
     
 
   
Total Refined Product Terminals
    2,680       9,931       7,251  
     
     
     
 
   
Subtotal
    18,953       39,206       20,253  
Rio Grande Pipeline Company
    6,910       6,910        
Intermediate Product Pipelines(2)
                 
Crude Oil Pipelines(2)
    4,937             (4,937 )
     
     
     
 
 
Total
  $ 30,800     $ 46,116     $ 15,316  
     
     
     
 


(1)  Includes shipments between Artesia and Moriarty and Artesia and Bloomfield.
 
(2)  These pipelines will not be contributed to our partnership.

Liquidity and Capital Resources

 
Cash flows and capital expenditures

       Holly Corporation utilizes a common treasury function for all of its subsidiaries, whereby all cash receipts are deposited in Holly Corporation bank accounts and all cash disbursements are made from these accounts. Cash receipts from customers and cash payments to vendors for Navajo Pipeline Co., L.P. (Predecessor) were recorded in these common accounts. Thus, prior to the acquisition of control of Rio Grande Pipeline Company no cash balances were reflected in the accounts of Navajo Pipeline Co., L.P. (Predecessor). Cash transactions handled by Holly Corporation for Navajo Pipeline Co., L.P. (Predecessor) were reflected in intercompany accounts receivable and accounts payable between the parent and the subsidiary.

       Cash flows from operations. Cash flows from operations increased from $0.2 million for the three months ended March 31, 2003 to $0.3 million for the three months ended March 31, 2004. Net income for the three months ended March 31, 2004 was approximately $9.6 million

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compared to a net loss of $0.4 million for the three months ended March 31, 2003. However, the net change in working capital reduced cash flow from operations by $0.3 million for the three months ended March 31, 2003 and $12.1 million for the three months ended March 31, 2004 as a result of the change in accounting policies related to intercompany and intracompany revenues. Depreciation increased cash flow from operations by approximately $0.8 million and items related to equity accounting versus consolidation of Rio Grande Pipeline Company increased cash flows from operations for the three months ended March 31, 2004 by approximately $1.0 million.

       Cash flows from operations for the year ended December 31, 2003 increased $1.6 million to $5.9 million from $4.3 million for the year ended December 31, 2002. Cash flows from operations for the year ended December 31, 2003 increased primarily due to an increase in non-cash items consisting of the following: (i) an increase in depreciation of $2.0 million; (ii) the reduction in equity and earnings of $1.8 million; and (iii) an increase in minority interest of $0.8 million when compared to the year ended December 31, 2002. However, net income for the year ended December 31, 2003 decreased by $2.1 million. In addition, increases in accounts payable and accrued liabilities increased cash flows by $5.8 million, while the increases in intercompany accounts receivable decreased cash flows by $6.7 million in 2003.

       Cash flows from operations for the year ended December 31, 2001 and the year ended December 31, 2002 were $10.3 million and $4.3 million, respectively. Cash flows for 2001 were substantially greater than 2002 primarily as a result of a substantial increase in intercompany accounts payable in 2001 related to the construction of the Bloomfield and Moriarty terminals, a new 10-inch intermediate products pipeline from Lovington to Artesia, as well as construction of additional compression facilities on the Moriarty to Bloomfield leased line.

       Cash flows from investing activities. Cash flows from investing activities decreased from $(0.2) million for the three months ended March 31, 2003 to $(2.6) million for the three months ended March 31, 2004. Investment in properties and equipment for the three months ended March 31, 2004 increased by approximately $1.3 million for new office facilities, a new pump station for the intermediate pipelines not being contributed to the partnership and pipeline expansions for the Rio Grande Pipeline.

       During the year ended December 31, 2003 approximately $6.8 million was expended on capital assets, including $3.4 million by Rio Grande Pipeline Company subsequent to June 30, 2003 and $1.4 million in connection with the acquisition of the Boise, Burley and Spokane terminals and the Woods Cross truck rack. An additional $1.9 million was expended on maintenance capital projects and/or construction in progress during the year ended December 31, 2003.

       Capital expenditures were $11.5 million in the year ended December 31, 2001 and $6.8 million in the year ended December 31, 2002, respectively. These expenditures related primarily to additions to the intermediate product pipelines (which will not be contributed to our partnership) and the terminals in Moriarty and Bloomfield, New Mexico.

       In 2003, Rio Grande Pipeline Company made cash distributions of $4.5 million to its owners subsequent to June 30, 2003, of which $1.4 million is reflected as a cash outflow in investing activities.

       During the three months ended March 31, 2004, $1.0 million was distributed to the owners of the minority interest in Rio Grande Pipeline Company.

       Cash flows from financing activities. Effective June 30, 2003, we acquired an additional 45% equity interest in Rio Grande Pipeline Company. On June 1, 2003, we acquired the Boise, Burley and Spokane terminals and the Woods Cross truck rack. Financing for these acquisitions totaled $30.1 million.

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Capital requirements

       Our pipeline and terminalling operations are capital intensive, requiring investments to expand, upgrade or enhance existing operations and to meet environmental and operations regulations. Our capital requirements have consisted of and are expected to continue to consist primarily of maintenance capital expenditures and expansion capital expenditures. Maintenance capital expenditures represent capital expenditures to replace partially or fully depreciated assets to maintain the operating capacity of existing assets and extend their useful lives. Expansion capital expenditures represent capital expenditures to expand the operating capacity of existing or new assets, whether through construction or acquisition. Repair and maintenance expenses associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred. Maintenance capital expenditures include expenditures required to maintain equipment reliability, tankage, and pipeline integrity and safety and to address environmental regulations. Expansion capital expenditures include expenditures to acquire assets to grow our business and to expand existing facilities, such as projects that increase throughput capacity on our pipelines and in our terminals. During the three years ended December 31, 2003, we incurred a total of $3.9 million in maintenance capital expenditures and expended $21.2 million for acquisitions and expansion and/or upgrades of our pipelines and terminal facilities.

       We have budgeted average annual maintenance capital expenditures for our operations of $1.5 million in each of 2004 and 2005. We anticipate that these capital expenditures will be funded with cash generated by operations.

       Our capital requirements over the past three years have been met with internally generated funds including short-term non-interest bearing funding from affiliates. It is anticipated that future expansion capital requirements will be provided through long-term borrowings or other debt financings and/or equity capital offerings.

 
Credit Agreement

       We will enter into a four-year $100 million senior secured revolving credit agreement in connection with the closing of this offering. Union Bank of California, N.A. will serve as administrative agent under this credit agreement.

       The credit agreement will be available to fund capital expenditures, acquisitions, working capital and for general partnership purposes. In addition, the credit agreement will be available to fund letters of credit up to a $50 million sub-limit. Up to $5 million will be available to fund distributions to unitholders. We expect to borrow $25 million under the credit agreement at the closing of the offering to fund a distribution to Holly Corporation, leaving approximately $75 million available for future borrowings. Under certain conditions specified in the credit agreement, only $60 million would be available for future borrowings.

       Following the closing of this offering and funding of the credit agreement, we will have the right to request an increase in the maximum amount of the agreement, up to $175 million. Such requests will become effective if (i) certain conditions specified in the credit agreement are met and (ii) existing lenders under the credit agreement or other financial institutions reasonably acceptable to the administrative agent commit to lend such increased amounts under the agreement.

       Our obligations under the credit agreement will be secured by substantially all of our assets. Indebtedness under the credit agreement will be non-recourse to our general partner and guaranteed by our subsidiaries.

       We may prepay all loans at any time without penalty. We will be required to reduce all working capital borrowings under the credit agreement to zero for a period of at least 15 consecutive days once each twelve month period prior to the maturity date of the agreement.

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       Indebtedness under the credit agreement will bear interest, at our option, at either (i) the base rate as announced by the administrative agent plus an applicable margin (ranging from 0.25% to 1.00%) or (ii) at a rate equal to LIBOR plus an applicable margin (ranging from 1.50% to 2.25%). In each case, the applicable margin will be based upon the ratio of our funded debt (as defined in the credit agreement) to EBITDA (as defined in the credit agreement). We will incur a commitment fee on the unused portion of the credit agreement at a rate for the four most recently completed fiscal quarters of 37.5 or 50.0 basis points based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters. The credit agreement matures in July 2008. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.

       The credit agreement prohibits us from making distributions to unitholders if any potential default or event of default, as defined in the credit agreement, occurs or would result from the distribution. In addition, the credit agreement will contain various covenants that limit, among other things, our ability to:

  •  incur indebtedness;
 
  •  grant liens;
 
  •  make certain loans, acquisitions and investments;
 
  •  make any material change to the nature of our business;
 
  •  acquire another company; or
 
  •  enter into a merger, consolidation or sale of assets.

       The credit agreement also contains covenants requiring us to maintain on a quarterly basis:

  •  a ratio of not less than 3.50:1.00 of EBITDA to interest expense, each measured for the preceding four quarter period;
 
  •  a ratio of not more than 3.50:1.00 of debt at the end of the quarter to EBITDA for the preceding four quarter period; and
 
  •  a minimum tangible net worth of $50.0 million plus 50% of the gross proceeds of all equity issuances by us after this offering.

       If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. Each of the following will be an event of default:

  •  failure to pay any principal when due or any interest, fees or other amount within certain grace periods;
 
  •  failure of any representation or warranty to be true and correct in any material respect;
 
  •  failure to perform or otherwise comply with the covenants in the credit agreement or other loan documents, subject to certain grace periods;
 
  •  default by us or any of our subsidiaries on the payment of any other indebtedness in excess of $5.0 million, or any default in the performance of any obligation or condition with respect to such indebtedness beyond the applicable grace period if the effect of the default is to permit or cause the acceleration of the indebtedness;
 
  •  termination of any material agreements, including the pipelines and terminals agreement and the omnibus agreement;
 
  •  default under any material agreement if such default could have a material adverse effect on us;
 
  •  bankruptcy or insolvency events involving us or our subsidiaries;

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  •  the entry, and failure to pay, one or more adverse judgments in excess of $5.0 million against which enforcement proceedings are brought or that are not stayed pending appeal; and
 
  •  the minimum revenue commitment being decreased to an amount below $6,638,000 per quarter pursuant to the terms of our pipelines and terminals agreement;
 
  •  a Change of Control (as defined in the credit agreement).

       The credit agreement is subject to a number of conditions, including the negotiation, execution and delivery of definitive documentation.

 
Contractual Obligations and Contingences

       Our contractual obligations at March 31, 2004 consisted of the following (in thousands):

                                         
Payments Due by Period

Less than Over 5
Total 1 Year 2-3 Years 4-5 Years Years





Pipeline operating lease
  $ 17,225     $ 5,300     $ 10,600     $ 1,325        
Short-term debt
  $ 30,082       30,082                    

       On a pro forma basis, after giving effect to the offering and the application of the proceeds therefrom to repay certain short-term debt, our contractual obligations at March 31, 2004 consisted of the following (in thousands):

                                         
Payments Due by Period

Less than Over 5
Total 1 Year 2-3 Years 4-5 Years Years





Pipeline operating lease
  $ 17,225     $ 5,300     $ 10,600     $ 1,325        
Debt under the new credit agreement
  $ 25,000                 $ 25,000        

Impact of Inflation

       Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2001, 2002, 2003 or the three months ended March 31, 2004.

Regulatory Matters

       Our interstate common carrier pipeline operations are subject to rate regulation by the FERC under the Interstate Commerce Act and the Energy Policy Act. Some of our intrastate pipeline operations are subject to regulation by the Texas Railroad Commission, the New Mexico Public Regulation Commission or the Idaho Public Utilities Commission. For more information on federal and state regulations affecting our business, please read “Business — Rate Regulation.”

Environmental Matters

       Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. For a complete discussion of the environmental laws and regulations affecting our business, please read “Business — Environmental Regulation.”

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Recent Accounting Pronouncements

       In June 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard (“SFAS”) No. 142 “Goodwill and Other Intangible Assets” which changes how goodwill and other intangible assets are accounted for subsequent to their initial recognition. SFAS No. 142 is effective for fiscal years beginning after December 15, 2001, with early adoption permitted; however, all goodwill and intangible assets acquired after June 30, 2001, are immediately subject to the provisions of this statement. We adopted the standard effective August 1, 2002 and there was no material effect on our financial condition, results of operations, or cash flows.

       In June 2001, FASB issued SFAS No. 143 “Accounting for Asset Retirement Obligations” which requires that the fair value for an asset retirement obligation be capitalized as part of the carrying amount of the long-lived asset if a reasonable estimate of fair value can be made. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002, with early adoption permitted. We adopted the standard effective August 1, 2002 and there was no material effect on our financial condition, results of operations, or cash flows.

       In August 2001, FASB issued SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This statement supersedes SFAS No. 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of”, but carries over the key guidance from SFAS No. 121 in establishing the framework for the recognition and measurement of long-lived assets to be disposed of by sale and addresses significant implementation issues. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001, with early adoption permitted. We adopted the standard effective August 1, 2002 and there was no material effect on our financial condition, results of operations, or cash flows.

       In June 2002, FASB issued SFAS No. 146 “Accounting for Certain Costs Associated with Exit or Disposal Activities” which nullifies Emerging Issues Task Force (“EITF”) 94-3 and requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred and establishes fair value as the objective for initial measurement of liabilities. This differs from EITF 94-3 which stated that liabilities for exit costs were to be recognized as of the date of an entity’s commitment to an exit plan. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. We adopted the standard on January 1, 2003, and there was no material effect on our financial condition, results of operations, or cash flows.

Critical Accounting Policies

       Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities as of the date of the financial statements. Actual results may differ from these estimates under different assumptions or conditions. We consider the following policies to be the most critical to understanding the judgments that are involved and the uncertainties that could impact our results of operations, financial condition and cash flows.

 
Revenue Recognition

       Revenues are recognized as products are shipped through our pipelines and terminals, except that prior to January 1, 2004 pipeline tariff and terminal services fee revenues were not recorded on services utilizing non-FERC regulated pipelines. These revenues had not previously been recognized as the pipelines and terminals were operated as a component of Holly Corporation’s petroleum refining and marketing business. Commencing January 1, 2004, we

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began charging Holly Corporation pipeline tariffs and terminal service fees as set forth in the pipelines and terminals agreement. Additional pipeline transportation revenues result from an operating lease by Alon of an interest in the capacity of one of our pipelines.

       The only revenues reflected in the historical financial data prior to January 1, 2004 are from (i) third parties who used our pipelines and terminals, (ii) Holly Corporation’s use of our FERC-regulated pipeline and (iii) Holly Corporation’s use of the Lovington crude pipelines, which will not be contributed to Holly Energy Partners, L.P. Upon the closing of the offering, we will receive revenues from Holly Corporation pursuant to the terms of the pipelines and terminals agreement. Please read “— Impact of Pipelines and Terminals Agreement.”

 
Long-lived Assets

       We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets. When assets are placed into service, we make estimates with respect to their useful lives that we believe are reasonable. However, factors such as competition, regulation or environmental matters could cause us to changes our estimates, thus impacting the future calculation of depreciation and amortization. We evaluate long-lived assets for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset’s carrying value exceeds its fair value. Estimates of future discounted cash flows and fair value of assets require subjective assumptions with regard to future operating results and actual results could differ from those estimates. No impairments of long-lived assets were recorded during the three years ended December 31, 2003 or during the three months ended March 31, 2004.

 
Contingencies

       In the future, we will be subject to proceedings, lawsuits and other claims related to environmental, labor, product and other matters. We are required to assess the likelihood of any adverse judgments or outcomes to these matters as well as potential ranges of probable losses. A determination of the amount of reserves required, if any, for these contingencies is made after careful analysis of each individual issue. The required reserves may change in the future due to developments in each matter or changes in approach such as a change in settlement strategy in dealing with these potential matters.

       The omnibus agreement also provides that Holly Corporation will indemnify us up to $15 million for certain environmental matters for a period of ten years. Please read “Business — Environmental Regulation,” and “Certain Relationships and Related Transactions — Omnibus Agreement” for a more complete description of these provisions.

Quantitative and Qualitative Disclosures About Market Risk

       Market risk is the risk of loss arising from adverse changes in market rates and prices. Because we do not own the refined product that is shipped on our pipelines or throughput in our terminals, we are not directly exposed to refined product or commodity type risk. Debt that we incur under our credit agreement will bear variable interest and will expose us to interest rate risk. Unless interest rates increase significantly in the future, our exposure to interest rate risk should be minimal. We may use certain derivative instruments to hedge our exposure to variable interest rates. We do not currently have in place any hedges or forward contracts.

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BUSINESS

Overview

       Holly Energy Partners is a Delaware limited partnership recently formed by Holly Corporation. We operate a system of refined product pipelines and distribution terminals primarily in West Texas, New Mexico, Utah and Arizona. We generate revenues by charging tariffs for transporting refined products through our pipelines and by charging fees for terminalling refined products and other hydrocarbons, and storing and providing other services at, our terminals. We do not take ownership of products that we transport or terminal and therefore we are not directly exposed to changes in commodity prices. We serve Holly Corporation’s refineries in New Mexico and Utah under a 15 year pipelines and terminals agreement. Our assets include:

  •  Refined Product Pipelines:

  •  approximately 780 miles of refined product pipelines, including 340 miles of leased pipelines, that transport gasoline, diesel, and jet fuel from Holly Corporation’s Navajo Refinery in New Mexico to its customers in the metropolitan and rural areas of Texas, New Mexico, Arizona, Colorado, Utah and northern Mexico; and
 
  •  a 70% interest in the Rio Grande Pipeline Company, a joint venture that owns a 249-mile refined product pipeline, that transports liquid petroleum gases, or LPGs, from West Texas to the Texas/ Mexico border near El Paso for further transport into northern Mexico.

  •  Refined Product Terminals:

  •  five refined product terminals (two of which are 50% owned), located in El Paso, Texas; Moriarty, Bloomfield and Albuquerque, New Mexico; and Tucson, Arizona, with an aggregate capacity of approximately 1.1 million barrels, that are integrated with our refined product pipeline system;
 
  •  three refined product terminals (two of which are 50% owned), located in Burley and Boise, Idaho and Spokane, Washington, with an aggregate capacity of approximately 514,000 barrels, that serve third party common carrier pipelines;
 
  •  one refined product terminal near Mountain Home, Idaho with a capacity of 120,000 barrels, that serves a nearby United States Air Force Base; and
 
  •  two refined product truck loading racks, one located within Holly Corporation’s Navajo Refinery that is permitted to load over 40,000 bpd of light refined products, and one located within Holly Corporation’s Woods Cross Refinery near Salt Lake City, Utah, that is permitted to load over 25,000 bpd of light refined products.

       In addition, we have an option to purchase two intermediate product pipelines from Holly Corporation. These pipelines transport crude oil and feedstocks from Holly Corporation’s Lovington facility to its Artesia facility. These pipelines are each 65 miles long and have a current aggregate throughput capacity of 84,000 bpd.

Our Relationship with Holly Corporation

       The substantial majority of our business is devoted to providing transportation and terminalling services to Holly Corporation, an independent petroleum refiner and marketer that produces high value light products such as gasoline, diesel fuel and jet fuel. For the year ended December 31, 2003, Holly Corporation accounted for approximately $30.2 million, or 57.3%, of our pro forma revenues. For the three months ended March 31, 2004, Holly Corporation accounted for approximately $9.2 million, or 59.6%, of our pro forma revenues. We expect to

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continue to derive a substantial majority of our revenues from Holly Corporation for the foreseeable future. Please read “Risk Factors — Risks Inherent in Our Business — An adverse decision in a lawsuit pending between Holly Corporation and Frontier Oil Corporation could have a material adverse effect on Holly Corporation’s financial condition and results of operations and therefore our results of operations.”

       Holly Corporation owns and operates the Navajo Refinery, the largest refinery in New Mexico, consisting of refining facilities that are located 65 miles apart in Artesia and Lovington and operated in conjunction with each other. The Navajo Refinery, which has operated continuously since its acquisition by Holly Corporation in 1969, is one of the most efficient and technologically advanced refineries in the geographic area it serves, with a Nelson Complexity Index rating of 10.0. In December 2003, the Navajo Refinery completed an $85.0 million expansion project at the Artesia facility that increased its crude oil processing capacity from 60,000 bpd to 75,000 bpd and allowed the refinery to meet or exceed the federally mandated clean air requirements for gasoline. The majority of our operations are located within Holly Corporation’s New Mexico refining market area. Holly Corporation relies on us to provide almost all of the light refined product transportation and terminalling services it requires to support its New Mexico refining operations. For the year ended December 31, 2003 and the three months ended March 31, 2004, we transported and terminalled approximately 99% of the light refined products produced by the Navajo Refinery.

       Holly Corporation also operates a crude oil refinery in Woods Cross, Utah, near Salt Lake City, primarily serving markets in Utah and Idaho. The Woods Cross Refinery has a current crude oil processing capacity of 25,000 bpd and, for the period from June 1, 2003 to March 31, 2004, it processed 22,119 bpd of crude oil, utilizing approximately 88.4% of the refinery’s capacity. Since June 1, 2003, the date Holly Corporation acquired the Woods Cross Refinery, through March 31, 2004, we terminalled 100% of the light refined products produced by the Woods Cross Refinery.

       Holly Corporation also operates a refinery in Great Falls, Montana, primarily serving markets in Montana, with a current crude oil processing capacity of 8,000 bpd. We have no operations relating to the Montana Refinery.

       Holly Corporation currently markets the light refined products it produces in Texas, New Mexico, Arizona, Montana, Utah, Colorado, Idaho, Washington, and northern Mexico. For more information on Holly Corporation’s marketing activities, please read “— Holly Corporation’s Refining Operations — Marketing.”

       Holly Corporation has a significant interest in our partnership through its indirect ownership of a 56% limited partner interest and a 2% general partner interest. Holly Corporation’s common stock trades on the New York Stock Exchange under the symbol “HOC.” For the year ended December 31, 2003 and the three months ended March 31, 2004, Holly Corporation had revenues of $1.4 billion and $463 million, respectively, and net income of $46.1 million and $14.0 million, respectively. Holly Corporation is subject to the information requirements of the Securities Exchange Act of 1934. Please read “Where You Can Find More Information.”

 
Pipelines and Terminals Agreement

       Concurrently with the closing of this offering, we will enter into a 15 year pipelines and terminals agreement with Holly Corporation. Under this agreement, Holly Corporation will pay us fees that we believe are comparable to those that would be charged by third parties. Holly Corporation will also agree to transport on our refined product pipelines and throughput in our terminals a volume of refined products that will result in minimum revenues of $35.4 million in the first year. This minimum revenue commitment will increase each year at a rate equal to the percentage change in the producer price index, but will not decrease as a result of a decrease in the producer price index. Holly Corporation will pay the published tariff rates on the pipelines and contractually agreed upon fees at the terminals. The tariffs will adjust annually at a rate equal to

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the change in the producer price index. The terminal fees will adjust annually based upon an index comprised of comparable fees posted by third parties. Holly Corporation’s minimum revenue commitment will apply only to our initial assets and may not be spread among assets we subsequently acquire. On a pro forma basis, we would have received $30.2 million in revenue from Holly Corporation for the use of our pipelines and terminals during the year ended December 31, 2003. Because we began charging Holly Corporation the fees set forth in the pipelines and terminals agreement beginning January 1, 2004, we received actual revenues from Holly Corporation of $9.2 million in the first quarter of 2004. If Holly Corporation fails to meet its minimum revenue commitment in any quarter, it will be required to pay us in cash the amount of any shortfall by the last day of the month following the end of the quarter. A shortfall payment may be applied as a credit in the following four quarters after Holly Corporation’s minimum obligations are met.

       At Holly Corporation’s request, we will use our best efforts to transport by pipeline each month during the term of the agreement up to 40,000 bpd from Artesia to El Paso and up to 40,000 bpd from Artesia to Moriarty/ Bloomfield, subject to our common carrier duty to pro-ration capacity, where applicable. We have also agreed to provide terminalling services for all of Holly Corporation’s barrels shipped on those pipelines to those destinations.

       Holly Corporation’s obligations under this agreement may be proportionately reduced or suspended if Holly Corporation (1) shuts down or reconfigures one of its refineries (other than for planned maintenance turnarounds) and (2) reasonably believes in good faith that such event will jeopardize its ability to satisfy its minimum revenue obligations. Holly Corporation will be required to give at least twelve months’ advance notice of any long-term shut-down or material reconfiguration. Holly Corporation will propose new minimum obligations that proportionally reduce the affected obligations. If we do not agree with this reduction, any change in Holly Corporation’s obligations will be determined by binding arbitration.

       Furthermore, if new laws or regulations that affect terminals or pipelines generally are enacted that require us to make substantial and unanticipated capital expenditures at the pipelines or terminals, we will have the right to impose a monthly surcharge on Holly Corporation for the use of the terminals or to file for an increased tariff rate for use of the pipelines to cover Holly Corporation’s pro rata portion of the cost of complying with these laws or regulations, after we have made efforts to mitigate their effect. We and Holly Corporation will negotiate in good faith to agree on the level of the monthly surcharge or increased tariff rate.

       Holly Corporation’s obligations under this agreement may be temporarily suspended during the occurrence of an event that is outside the control of the parties that renders performance impossible with respect to an asset for at least 30 days. An event with a duration of longer than one year would allow us or Holly Corporation to terminate the contract.

       Pursuant to the terms of the agreement, Holly Corporation has agreed to maintain commercially reasonable business interruption insurance for the benefit of its refinery assets as well as our pipelines and terminals. We reimburse Holly Corporation for the costs associated with our portion of the insurance. To the extent that Holly Corporation receives benefits under this policy, Holly Corporation has agreed to apply a portion of such amounts to the extent necessary to satisfy its minimum revenue commitment under the pipelines and terminals agreement. Allocation of business interruption insurance proceeds will be proportionate to the loss in earnings before interest, taxes, depreciation and amortization, or EBITDA, sustained by Holly Corporation and our partnership as a result of the interruption.

       Holly Corporation has agreed not to challenge, or to cause others to challenge or assist others in challenging, our tariff rates for the term of the pipelines and terminals agreement. This agreement does not prevent other current or future shippers from challenging our tariff rates. At the end of the agreement, Holly Corporation will be free to challenge, or to cause others to challenge or assist others in challenging, our tariff rates.

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       During the term of the agreement, we have agreed not to reverse the direction of any of our pipelines or to connect any other pipelines to our pipelines or terminals without the consent of Holly Corporation.

       Holly Corporation’s obligations under this agreement will not terminate if Holly Corporation and its affiliates no longer own the general partner. This agreement may be assigned by Holly Corporation only with the consent of our conflicts committee.

       Upon termination of the agreement, Holly Corporation will have a limited right of first refusal giving it the right to enter into a new pipelines and terminals agreement with us pursuant to which Holly Corporation will agree to match any commercial terms offered to us by a third party.

       To the extent Holly Corporation does not extend or renew the pipelines and terminals agreement, our financial condition and results of operations may be adversely affected. The majority of our assets were constructed or purchased to service Holly Corporation’s refining and marketing supply chain and are well-situated to suit Holly Corporation’s needs. As a result, we would expect that even if this agreement is not renewed, Holly Corporation would continue to use our pipelines and terminals. However, we cannot assure you that Holly Corporation will continue to use our facilities or that we will be able to generate additional revenues from third parties. Please read “Risk Factors — Risks Inherent in Our Business.”

       From time to time Holly Corporation considers changes to its refineries. Those changes may involve new facilities, reduction in certain operations or modifications of facilities or operations. Changes may be considered to meet market demands, to satisfy regulatory requirements or environmental and safety objectives, to improve operational efficiency or for other reasons. One such project recently completed is an $85.0 million expansion project at Holly Corporation’s Artesia facility that expanded total crude oil processing capacity from 60,000 bpd to 75,000 bpd and allowed the refinery to meet or exceed current federally mandated clean air requirements for gasoline.

       Holly Corporation has advised us that although it continually considers the types of matters referred to above, it currently does not intend to close or dispose of the refineries currently served by our pipelines and terminals or to cause any changes that would have a material adverse effect on us. Holly Corporation is, however, actively managing its assets and operations, and, therefore, changes of some nature, possibly material to us, are likely to occur at some point in the future.

Business Strategies

       Our primary business objective is to increase distributable cash flow per unit by executing the following strategies:

       Generate stable cash flows. We generate revenues from customers who pay us fees primarily based on the volume of refined products shipped in our pipelines or stored in or distributed from our terminals. We have no direct commodity price risk because we do not own any of the products transported on our pipelines or distributed from our terminals. In order to ensure stable cash flows, we will enter into a long-term pipelines and terminals agreement pursuant to which Holly Corporation will agree to pay us a guaranteed minimum amount of revenues. The initial annual minimum revenue commitment of $35.4 million equals approximately 67.2% of our pro forma revenues for 2003. We believe that the fee-based nature of our business and the long-term nature of our contracts will provide us with stable cash flows.

       Increase our pipeline and terminal throughput. We have available capacity in many of our pipelines and terminals that can allow us to increase throughput without significant capital expenditures. In 2003, we averaged 50.9% capacity utilization on our three main refined products pipelines. We believe that the recent 15,000 bpd expansion of Holly Corporation’s Navajo Refinery and growth in demand for light refined products in the markets we serve will result in

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increased utilization of our pipelines and terminals. For example, for the three months ended March 31, 2004, we averaged 60.4% capacity utilization on our three main refined product pipelines. As a result of our strategic position within Holly Corporation’s supply chain, substantially all of the new barrels produced as a result of the 2003 Navajo Refinery expansion are being transported on our pipelines. In addition, as part of this expansion, Holly Corporation built the infrastructure necessary to expand the Navajo Refinery by an additional 5,000 bpd to a total production of 80,000 bpd, if refined product demand increases in the future.

       Undertake economic construction and expansion opportunities. We continually evaluate opportunities to expand our asset base. Since 1996, our management team has constructed or leased approximately 500 miles of additional pipelines and has constructed or expanded terminals providing approximately 482,000 barrels of additional storage capacity. These assets have provided shippers with access to new markets in northern Mexico, northern New Mexico, southern Colorado and southern Utah. We will continue to consider extending our existing refined product pipelines or constructing new refined product pipelines and terminals to meet rising demand in high growth areas in the southwestern United States, northern Mexico and the Rocky Mountain region in the United States.

       Pursue strategic and accretive acquisitions that complement our existing asset base. We plan to pursue acquisitions from third parties of energy transportation and distribution assets that are complementary to those we currently own. We will pursue these acquisitions independently as well as jointly with Holly Corporation. For example, in 2003, we acquired terminals in Burley and Boise, Idaho, and Spokane, Washington providing over 514,000 barrels of additional storage capacity and an additional 45% interest in the Rio Grande Pipeline Company. Future acquisition targets may include assets to be directly integrated into our existing refined product distribution chain, such as pipelines, terminals and qualified processing assets, or acquisitions of related businesses in which we are not currently active. In addition, we currently have an option to purchase two intermediate pipelines from Holly Corporation pursuant to the omnibus agreement and may have the opportunity to acquire other pipeline or terminal assets associated with Holly Corporation’s refineries in the future.

Competitive Strengths

       We believe we are well-positioned to execute our business strategies successfully using the following competitive strengths:

       Substantially all of our assets are located in markets with above average population growth. Our pipelines and terminals serve our customers’ marketing operations in the Southwest and Rocky Mountain regions of the United States as well as northern Mexico. In many of our core markets, demand for light refined products exceeds local production, due in part to above average population growth. We expect that the population growth in the states of Texas, New Mexico, Colorado and Arizona will result in increased demand for light refined products shipped on our pipelines.

       We will operate a substantial part of our business under long-term contracts. We will conduct a significant portion of our operations pursuant to long-term contracts, which we believe will enhance the stability and predictability of our revenues and cash flows. Revenues from contracts extending beyond one year constituted approximately 95% of our pro forma revenues for 2003 and for the first quarter of 2004. In addition, where we operate under shorter-term contracts, we believe our long-standing customer relationships will lead to repeat business and the renewal of short-term contracts.

       Our assets are modern, efficient, and well maintained. We continually invest in the maintenance and integrity of our assets, including state-of-the-art internal mechanical integrity inspection and repair programs to comply with federal regulations. Since 1998, we have inspected and repaired approximately 98% of the total miles of our pipelines using internal

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inspection devices known as “smart pigs” that have instruments capable of detecting cracks, line erosion and other structural deficiencies. The operating pressures of these lines have been validated with recent hydrotesting. All of our assets are operated via satellite communications systems from our control center. The control center operates with state-of-the-art computer systems designed to continuously monitor real time operational data, including product quantities, flow rates and pressures.

       We have a strategic relationship with Holly Corporation. Substantially all of our refined product pipelines are directly linked to Holly Corporation’s refineries and provide Holly Corporation with the safest and most cost-effective means to distribute light refined products to its major markets. For the year ended December 31, 2003 and the three months ended March 31, 2004, Holly Corporation transported through our refined product pipelines or loading racks approximately 99% of the light refined products from its Navajo Refinery and 100% from its Woods Cross Refinery. Holly Corporation will agree to continue using our assets to transport, terminal and store light refined products pursuant to the pipelines and terminals agreement. Furthermore, Holly Corporation has a significant economic interest to see that our pipeline and terminal assets are managed in the best interests of unitholders because it and its affiliates will own the 2% general partner interest in us and a 56% limited partner interest in us and the incentive distribution rights.

       We are contractually and strategically positioned to benefit from growth initiatives by Holly Corporation. In the past year, we benefited from Holly Corporation’s acquisition of a group of terminals in the Northwest and a 15,000 bpd expansion of its Navajo Refinery. In the event that Holly Corporation further expands its refineries, we believe that the additional production may also be transported, stored and distributed through our existing pipelines and terminals. Under the omnibus agreement, Holly Corporation will be required to grant us an opportunity to acquire certain types of transportation and distribution assets that are part of certain acquisitions it makes.

       We have the financial flexibility to pursue expansion and acquisition opportunities. We anticipate having a $100.0 million credit agreement, of which we expect to have $75.0 million of borrowing capacity available for general partnership purposes, including capital expenditures and acquisitions, following this offering. In addition, we believe that we have debt capacity beyond that available under our credit agreement. In combination with our ability to issue new partnership units, we have significant resources to finance expansion projects and acquisitions.

       We have an experienced management team. We believe we will benefit from the experience and long-standing industry relationships of our senior management team. Our senior management has operated Holly Corporation’s pipeline and terminals business for over 15 years and has an average of over 20 years of experience in the energy industry.

 
Construction and Acquisition History

       We have developed our business through pipeline construction, leases and various acquisitions including the following:

  •  In 1996, we entered into a long-term lease for 155 miles of 8-inch pipeline from White Lakes, New Mexico to Moriarty, New Mexico;
 
  •  In 1996, we entered into a long-term lease for 191 miles of 8-inch pipeline from Moriarty, New Mexico to Bloomfield, New Mexico;
 
  •  In 1997, we constructed 98 miles of 12-inch pipeline from Orla, Texas to El Paso, Texas;
 
  •  In 1997, we acquired a 25% interest in Rio Grande Pipeline Company;
 
  •  In 1998, we constructed 60 miles of 12-inch pipeline from Artesia, New Mexico to White Lakes, New Mexico;

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  •  In 1998, we constructed the Moriarty Terminal;
 
  •  In 1998, we constructed the Bloomfield Terminal;
 
  •  In 2002, we expanded the El Paso Terminal by 100,000 bbls;
 
  •  In 2003, we acquired an additional 45% interest in Rio Grande Pipeline Company; and
 
  •  In 2003, we acquired the Boise and Burley, Idaho, and Spokane, Washington terminals and the truck rack located in the Woods Cross Refinery.

Pipelines

 
Overview

       Our refined product pipelines transport light refined products from Holly Corporation’s Navajo Refinery, as well as from a third party, to customers in the metropolitan and rural areas of Texas, New Mexico, Arizona, Colorado, Utah and northern Mexico. The refined products transported in these pipelines include conventional gasolines, federal, state and local specification reformulated gasoline, low-octane gasoline for oxygenate blending, distillates that include high- and low-sulfur diesel and jet fuel and LPGs (such as propane, butane and isobutane).

       For the year ended December 31, 2003, gasoline, diesel and jet fuel represented approximately 63%, 28% and 9%, respectively, of the total throughput in our refined product pipelines. Our refined product pipelines were originally constructed between 1981 and 1999, except for the Artesia to El Paso pipeline, which was originally constructed in 1959. Our pipelines are regularly inspected and well maintained, and we believe they are in good repair. Generally, other than as provided in the pipelines and terminals agreement, all of our pipelines are unrestricted as to the direction in which product flows and the type of refined products that we can transport on them. The FERC regulates the transportation tariffs for interstate shipments on our refined product pipelines and state regulatory agencies regulate the transportation tariffs for intrastate shipments on our pipelines.

       The following table details the average aggregate daily number of barrels of refined products transported on our refined product pipelines in each of the periods set forth below for Holly Corporation and for third parties. We acquired the lease on the White Lakes Junction to Moriarty and the Moriarty to Bloomfield refined product pipeline segments in 1996 and began transporting refined products on these segments in November 1999. In the case of these pipeline segments, the throughput set forth below for 1999 reflects the average daily throughput from the date of the acquisition through the end of the year.

                                                   
Three Months
Ended
Year Ended December 31, March 31,


1999 2000 2001 2002 2003 2004






Refined products transported for (bpd):
                                               
Holly Corporation
    51,365       55,825       47,364       55,288       51,456       65,313  
Third parties
    8,630       11,023       12,888       13,553       14,238       12,650  
     
     
     
     
     
     
 
 
Total (bpd)
    59,995       66,848       60,252       68,841       65,694       77,963  
     
     
     
     
     
     
 
 
Total (mbbls)
    21,898       24,400       21,992       25,127       23,978       7,095  
     
     
     
     
     
     
 

       The following table sets forth certain operating data for each of our refined product pipelines. Except as shown below, we own 100% of our refined product pipelines. Throughput is the total average number of barrels per day transported on a pipeline, but does not aggregate barrels moved between different points on the same pipeline. Revenues reflect tariff revenues

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generated by barrels shipped from an origin to a delivery point on a pipeline. Revenues also include payments made by Alon USA, L.P. under capacity lease agreements on our Orla to El Paso pipeline. Under these agreements, we provide space on our pipeline for the shipment of up to 20,000 barrels of refined product per day. Alon pays us whether or not it actually ships the full volumes of refined products it is entitled to ship. To the extent Alon does not use its capacity, we are entitled to use it. We calculate the capacity of our pipelines based on the throughput capacity for barrels of gasoline equivalent that may be transported in the existing configuration; in some cases, this includes the use of flow improvers.
                                                                   
Year ended December 31, 2003

Holly
Approximate Corporation
Diameter Length Tariff(1) Capacity Capacity Throughput Throughput As Adjusted
Origin and Destination (inches) (miles) ($/bbl) (bpd) Utilization (bpd) (bpd) Revenues(2)









(in thousands)
Refined Product Pipelines:
                                                               
 
Artesia, NM to El Paso, TX
    6       156     $ 1.05       24,000       39%       9,400       9,400     $ 3,595  
 
Artesia, NM to Orla, TX to El Paso, TX
    8/12/8       215       1.05       60,000 (3)     67%       40,200       26,000       16,273  
 
Artesia, NM to Moriarty, NM(4)
    12/8       215       1.35       45,000       36%       16,200       16,200       9,407  
 
Moriarty, NM to Bloomfield, NM(4)
    8       191       2.25 (5)       (6)       (6)       (6)       (6)       (6)
Rio Grande Pipeline Company:
                                                               
 
Rio Grande Pipeline(7)
    8       249       1.37       24,000       77%       18,580       0       13,501  


(1)  Represents the initial tariff rate under the pipelines and terminals agreement with Holly Corporation. Certain of these tariff rates are reduced in the event certain throughput levels are achieved.
 
(2)  Represents actual revenues received from third parties, plus, in the case of revenues from Holly Corporation, historical volumes multiplied by tariffs set forth in the pipelines and terminals agreement.
 
(3)  Includes 20,000 bpd of capacity on the Orla to El Paso segment of this pipeline that is leased to Alon.
 
(4)  The White Lakes Junction to Moriarty segment of our Artesia to Moriarty pipeline and our Moriarty to Bloomfield pipeline is leased from Mid-America Pipeline Company, LLC under a long-term lease agreement.
 
(5)  Represents the tariff from Artesia to Bloomfield.
 
(6)  Capacity, utilization, throughput and revenues for this pipeline are reflected in the information for the Artesia to Moriarty pipeline.
 
(7)  We have a 70% joint venture interest in the entity that owns this pipeline. Capacity, throughput and revenues reflect a 100% interest. Control of the Rio Grande Pipeline Company was acquired on June 30, 2003.

       For the year ended December 31, 2003 and the three months ended March 31, 2004, Holly Corporation accounted for an aggregate of 78.3% and 83.8%, respectively, of the refined product volumes transported on our refined product pipelines (excluding the Rio Grande Pipeline). For the same periods, these pipelines transported approximately 99% of the light refined products transported by pipeline from the Navajo Refinery.

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       The following map shows our light refined product pipelines and the intermediate refined product pipelines owned by Holly Corporation, which we have an option to purchase:

(Diagram depicting our pipelines and the intermediate pipelines)

 
Refined Product Pipelines

       Artesia, New Mexico to El Paso, Texas. The Artesia to El Paso refined product pipeline was constructed in 1959 and consists of 156 miles of 6-inch pipeline. This pipeline is used for the shipment of refined products produced at Holly Corporation’s Navajo Refinery to our El Paso terminal, where we deliver to common carrier pipelines for local transportation to Arizona, northern New Mexico and northern Mexico and to the terminal’s truck rack for local delivery by tanker truck. Holly Corporation is the only shipper on this pipeline. The refined products shipped on this pipeline represented approximately 17.2% of the total light refined products produced at Holly Corporation’s Navajo Refinery during 2003 and 20.7% of the total light refined products for the three months ended March 31, 2004. Refined products produced at Holly Corporation’s Navajo Refinery destined for El Paso are transported on either this pipeline or our Artesia to Orla to El Paso pipeline.

       Artesia, New Mexico to Orla, Texas to El Paso, Texas. The Artesia to Orla to El Paso refined product pipeline is a common carrier pipeline regulated by the FERC and consists of three segments:

  •  an 8-inch, 81-mile segment from the Navajo Refinery to Orla, Texas, constructed in 1981;
 
  •  a 12-inch, 98-mile segment from Orla to outside El Paso, Texas, constructed in 1996; and
 
  •  an 8-inch, 35-mile segment from outside El Paso to our El Paso terminal, constructed in the mid 1950s.

       There are two shippers on this pipeline, Holly Corporation and Alon USA, L.P. In 2003 and the three months ended March 31, 2004, this pipeline transported approximately 47.4% of the light refined products produced at Holly Corporation’s Artesia facility to our El Paso terminal. During 2003 and the three months ended March 31, 2004, approximately 27,000 bpd of the product we transported for Holly Corporation was delivered to third-party pipelines from our El Paso terminal for further transportation to Arizona, northern New Mexico and northern Mexico;

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the balance of the product is distributed through the terminal’s truck rack for further delivery by tanker truck.

       At Orla, the pipeline receives volumes of gasoline and diesel from Alon’s 60,000 bpd Big Spring, Texas refinery through a tie-in to an Alon pipeline system. Alon has reserved an aggregate of 20,000 bpd of capacity on the segment of our pipeline from Orla to El Paso under three separate long-term capacity lease agreements, the earliest of which expires in August 2008. Each of these lease agreements provides for five-year extension options at Alon’s option. Under these agreements, Alon pays us for this capacity, without regard to the volumes of refined products it actually ships.

       Holly Corporation accounted for 64.5% and Alon accounted for 35.5% of volumes transported on this pipeline for the year ended December 31, 2003. For the same period, Holly Corporation accounted for 61.0% of the revenues generated by this pipeline and Alon accounted for 39.0%. For the three months ended March 31, 2004, Holly Corporation accounted for 72.2% of the volumes and 66.2% of the revenues for this pipeline, with Alon accounting for the balance.

       Artesia, New Mexico to Moriarty, New Mexico. The Artesia to Moriarty refined product pipeline consists of a 59.5-mile, 12-inch pipeline from Holly Corporation’s Artesia facility to White Lakes Junction, New Mexico that was constructed in 1999, and approximately 155 miles of 8-inch pipeline that was constructed in 1973 and extends from White Lakes Junction to our Moriarty terminal, where it also connects to our Moriarty to Bloomfield pipeline. We own the 12-inch pipeline from Artesia to White Lakes Junction. We lease the White Lakes Junction to Moriarty segment of this pipeline, and our Moriarty to Bloomfield pipeline described below, from Mid-America Pipeline Company, LLC under a long-term lease agreement entered into in 1996, which expires in 2007 and has one ten-year extension at our option. At our Moriarty terminal, volumes shipped on this pipeline can be transported to other markets in the area via tanker truck, including Albuquerque, Santa Fe and west Texas. The 155-mile White Lakes Junction to Moriarty segment of this pipeline is operated by Mid-America Pipeline Company, LLC (or its designee). Holly Corporation is the only shipper on this pipeline. We currently pay a monthly fee (which is subject to adjustments based on changes in the producer price index) of approximately $442,000 to Mid-America Pipeline Company, LLC to lease the White Lakes Junction to Moriarty and Moriarty to Bloomfield pipelines.

       Moriarty, New Mexico to Bloomfield, New Mexico. The Moriarty to Bloomfield refined product pipeline was constructed in 1973 and consists of 191 miles of 8-inch pipeline leased from Mid-America Pipeline Company, LLC. This pipeline serves our terminal in Bloomfield. At our Bloomfield terminal, volumes shipped on this pipeline are transported to other markets in the Four Corners area via tanker truck. This pipeline is operated by Mid-America Pipeline Company, LLC (or its designee). Holly Corporation is the only shipper on this pipeline.

 
Rio Grande Pipeline

       We own a 70% interest in Rio Grande Pipeline Company, a joint venture that owns a 249-mile, 8-inch common carrier LPG pipeline regulated by the FERC. The other owner of Rio Grande is a subsidiary of BP Plc. The pipeline originates from a connection with an Enterprise pipeline in West Texas at Lawson Junction, and terminates at the Mexican border near San Elizario, Texas, with a delivery point in San Elizario and an additional receipt point near Midland, Texas for ultimate use by PEMEX (the government-owned energy company of Mexico). The Rio Grande Pipeline Company does not own any facilities or pipelines in Mexico. The pipeline has a current capacity of approximately 24,000 bpd. This pipeline was originally constructed in the mid 1950s, was first reconditioned in 1988, and subsequently reconditioned in 1996 and 2003. Approximately 75 miles of this pipeline has been replaced with new pipe, and an additional 50 miles has been recoated. The pipeline is currently operated by Magellan Pipeline Company LLC, a former partner in Rio Grande Pipeline Company.

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       The joint venture was formed in 1996, at which time we contributed nearly 220 miles of pipeline from near Odessa, Texas to outside El Paso, Texas in exchange for a 25% interest in the joint venture. The Rio Grande Pipeline began operations in 1997. In June 2003, we acquired an additional 45% interest in the joint venture from Juarez Pipeline Co., an affiliate of The Williams Companies, Inc. for approximately $28.7 million. The pipeline is currently completing a reconditioning project that should facilitate an expansion to more than 32,000 bpd, if required. Our 70% share of this project is expected to be approximately $3.1 million. Currently, only LPGs are transported on this pipeline, and BP is the only shipper. BP’s contract provides that BP will ship a minimum average of 16,500 bpd for the duration of the agreement. The tariff rates and shipping regulations are regulated by the FERC. For the years ended December 31, 2001, 2002 and 2003, BP paid $12.5 million, $14.2 million and $13.5 million pursuant to its contract.

       An officer of Holly Logistic Services, L.L.C. is one of two members of Rio Grande Pipeline Company’s management committee. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of our anticipated capital expenditures with respect to this pipeline.

Refined Product Terminals

       Our refined product terminals receive products from pipelines and Holly Corporation’s Navajo and Woods Cross refineries and distribute them to Holly Corporation and third parties, who in turn deliver them to end-users and retail outlets. Our terminals are generally complementary to our pipeline assets and serve Holly Corporation’s marketing activities. Terminals play a key role in moving product to the end-user market by providing the following services:

  •  distribution;
 
  •  blending to achieve specified grades of gasoline;
 
  •  other ancillary services that include the injection of additives and filtering of jet fuel; and
 
  •  storage and inventory management.

       Typically, our refined product terminal facilities consist of multiple storage tanks and are equipped with automated truck loading equipment that operates 24 hours a day. This automated system provides for control of security, allocations, and credit and carrier certification by remote input of data by our customers. In addition, nearly all of our terminals are equipped with truck loading racks capable of providing automated blending to individual customer specifications.

       Our refined product terminals derive most of their revenues from terminalling fees paid by customers. We charge a fee for transferring refined products from the terminal to trucks or to pipelines connected to the terminal. In addition to terminalling fees, we generate revenues by charging our customers fees for blending, injecting additives, and filtering jet fuel. Upon execution of the pipelines and terminals agreement, Holly Corporation will account for the substantial majority of our refined product terminal revenues.

       For the year ended December 31, 2003, gasoline represented approximately 63% of the total volume of refined products distributed through our product terminals, while distillates represented approximately 37%.

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       The table below sets forth the total average throughput for our refined product terminals in each of the periods presented:

                                                   
Three Months
Ended
Year Ended December 31, March 31,


1999 2000 2001 2002 2003 2004






Refined products terminalled for (bpd):
                                               
Holly Corporation
    70,364       80,556       69,751       81,592       88,859       115,581  
Third parties
    5,939       11,243       13,269       12,751       21,133       25,798  
     
     
     
     
     
     
 
 
Total (bpd)
    76,303       91,799       83,020       94,343       109,992       141,379  
     
     
     
     
     
     
 
 
Total (mbbls)
    27,851       33,506       30,302       34,435       40,147       12,866  
     
     
     
     
     
     
 

       The following table outlines the location of our refined product terminals and their storage capacities, number of tanks, supply source, mode of delivery and average throughput for the year ended December 31, 2003:

                                   
Storage Average
Capacity Number Supply Mode of Throughput
Terminal Location (bbls) of Tanks Source Delivery (bpd)






El Paso, TX
    507,000       16     Pipeline/rail  
Truck/ Pipeline
    48,400  
Moriarty, NM
    189,000       9     Pipeline  
Truck
    9,600  
Bloomfield, NM
    193,000       7     Pipeline  
Truck
    6,600  
Albuquerque, NM(1)
    64,000       9     Pipeline  
Truck
    7,900  
Tucson, AZ(2)
    176,000       9     Pipeline  
Truck
    9,600  
Mountain Home, ID(3)
    120,000       3     Pipeline  
Pipeline
    1,500  
Boise, ID(1)(4)
    111,000       9     Pipeline  
Pipeline
    (5)  
Burley, ID(1)(4)
    70,000       7     Pipeline  
Truck
    2,700  
Spokane, WA(4)
    333,000       32     Pipeline/rail  
Truck
    13,000  
Artesia facility truck rack
    N/A       N/A     Refinery  
Truck
    4,800  
Woods Cross facility truck rack(4)
    N/A       N/A     Refinery  
Truck/Pipeline
    21,200  
     
                     
 
 
Total
    1,763,000                       125,300  
     
                     
 


(1)  We have a 50% ownership interest in these terminals. The capacity and throughput information represents the proportionate share of capacity and throughput attributable to our ownership interest.
 
(2)  We have a 50% ownership interest in the improvements and equipment at this terminal. We lease the remaining 50% of the improvements and equipment from Kaneb Pipeline Co., the other owner. We hold leasehold interests in the underlying land.
 
(3)  Handles only jet fuel.
 
(4)  Average throughput is calculated from June 1, 2003, the date of acquisition.
 
(5)  The operations of this terminal are seasonal and it has seen limited use since its acquisition in June 2003.

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       The following map shows our light refined product terminals and truck racks:

(DIAGRAM DEPICTING OUR TERMINALS AND TRUCK RACKS)

       El Paso terminal. We receive light refined products at this terminal from Holly Corporation’s Artesia facility through our Artesia to El Paso and Artesia to Orla to El Paso pipelines and by rail that account for approximately 75% of the volumes at this terminal. We also receive product from Alon’s Big Spring, Texas refinery that accounted for approximately 25% of the volumes at this terminal in 2003. Refined products received at this terminal are sold locally via the truck rack or transported to our Tucson terminal on Kinder Morgan Energy Partners L.P.’s East System pipeline, to our Albuquerque terminal on ChevronTexaco’s Albuquerque pipeline, and to northern Mexico on ChevronTexaco’s Juarez pipeline. Competition in this market includes a refinery and terminal owned by Western Refining, a joint venture pipeline and terminal owned by ConocoPhillips and Valero L.P. and a terminal connected to the Longhorn Pipeline that is currently inactive.

       Moriarty terminal. We receive light refined products at this terminal from Holly Corporation’s Artesia facility through our pipelines. Refined products received at this terminal are sold locally via the truck rack. Holly Corporation is our only customer at this terminal. There are no competing terminals in Moriarty.

       Bloomfield terminal. We receive light refined products at this terminal from Holly Corporation’s Artesia facility through our pipelines. Refined products received at this terminal are sold locally via the truck rack. Holly Corporation is our only customer at this terminal. Competition in this market includes a refinery and terminal owned by Giant Industries.

       Albuquerque terminal. We and ConocoPhillips each own a 50% interest in the Albuquerque terminal. We receive light refined products from Holly Corporation that are transported on ChevronTexaco’s Albuquerque pipeline from our El Paso terminal and account for over 90% of the volumes at this terminal. We also receive product from ConocoPhillips and Valero that are transported to the Albuquerque terminal on Valero, L.P.’s West Emerald Pipeline from its McKee, Texas refinery. Competition in the Albuquerque market includes terminals owned by ChevronTexaco, ConocoPhillips, Giant and Valero.

       Tucson terminal. We and Kaneb Pipeline Co. each own a 50% interest in the improvements and equipment at the Tucson terminal. We lease the remaining 50% of the improvements and equipment at the terminal from Kaneb. We hold leasehold interests in the underlying land.

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We receive light refined products at this terminal from Kinder Morgan’s East System pipeline, which transports refined products from Holly Corporation’s Artesia facility that it receives at our El Paso terminal. Competition in this market includes terminals owned by Kinder Morgan and CalJet.

       Boise terminal. We and Sinclair each own a 50% interest in the Boise terminal. Sinclair is the operator of the terminal. The Boise terminal receives light refined product from Holly Corporation and Sinclair shipped through ChevronTexaco’s pipeline originating in Salt Lake City, Utah. The Woods Cross Refinery, as well as other refineries in Salt Lake City area, and Pioneer’s terminal in Salt Lake City are connected to the ChevronTexaco pipeline. All loading of products out of the Boise terminal is conducted at ChevronTexaco’s loading rack, which is connected to the Boise terminal by pipeline. Holly Corporation and Sinclair are the only customers at this terminal.

       Burley terminal. We and Sinclair each own a 50% interest in the Burley terminal. Sinclair is the operator of the terminal. The Burley terminal receives product from Holly Corporation and Sinclair shipped through ChevronTexaco’s pipeline originating in Salt Lake City, Utah. Holly Corporation and Sinclair are the only customers at this terminal.

       Spokane terminal. This terminal is connected to the Woods Cross Refinery via a ChevronTexaco common carrier pipeline. The Spokane terminal is also supplied by ChevronTexaco and Yellowstone pipelines and by rail and truck. Shell, ChevronTexaco and Holly Corporation are the major customers at this terminal. Other terminals in the Spokane area include terminals owned by ExxonMobil and ConocoPhillips.

       Mountain Home terminal. We receive jet fuel from third parties at this terminal that is transported on ChevronTexaco’s Salt Lake City to Boise, Idaho pipeline. We then transport the jet fuel from the Mountain Home terminal through our 13-mile, 4-inch pipeline to the United States Air Force Base outside of Mountain Home. Our pipeline associated with this terminal is the only pipeline that supplies jet fuel to the air base. We are paid a single fee from the Department of Fuel Supply Standard for injecting, storing, testing and transporting jet fuel at this terminal.

       Artesia facility truck rack. The truck rack at Holly Corporation’s Artesia facility loads light refined products produced at the facility onto tanker trucks for delivery to markets in the surrounding area. Holly Corporation is the only user of this truck rack.

       Woods Cross facility truck rack. The truck rack at Holly Corporation’s Woods Cross facility loads light refined products produced at the Woods Cross Refinery onto tanker trucks for delivery to markets in the surrounding area. Holly Corporation is the only user of this truck rack. Holly Corporation also makes transfers to a common carrier pipeline at this facility.

Pipeline and Terminal Control Operations

       All of our pipelines are operated via geosynchronous satellite, microwave, radio and frame relay communication systems from a central control room located in Artesia, New Mexico. We also monitor activity at our terminals from this control room.

       The control center operates with modern, state-of-the-art System Control and Data Acquisition, or SCADA, systems. Our control center is equipped with computer systems designed to continuously monitor operational data, including refined product and crude oil throughput, flow rates, and pressures. In addition, the control center monitors alarms and throughput balances. The control center operates remote pumps, motors, engines, and valves associated with the delivery of refined products and crude oil. The computer systems are designed to enhance leak-detection capabilities, sound automatic alarms if operational conditions outside of pre-established parameters occur, and provide for remote-controlled shutdown of pump stations on the pipelines. Pump stations and meter-measurement points on the pipelines are linked by satellite or

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telephone communication systems for remote monitoring and control, which reduces our requirement for full-time on-site personnel at most of these locations.

Safety and Maintenance

       We perform preventive and normal maintenance on all of our pipeline systems and make repairs and replacements when necessary or appropriate. We also conduct routine and required inspections of our pipelines and other assets as required by code or regulation. We inject corrosion inhibitors into our mainlines to help control internal corrosion. External coatings and impressed current cathodic protection systems are used to protect against external corrosion. We conduct all cathodic protection work in accordance with National Association of Corrosion Engineers standards. We continually monitor, test, and record the effectiveness of these corrosion inhibiting systems.

       We monitor the structural integrity of selected segments of our pipeline systems through a program of periodic internal inspections using both “dent pigs” and electronic “smart pigs,” as well as hydrostatic testing that conforms to Federal standards. We follow these inspections with a review of the data, and we make repairs as required to ensure the integrity of the pipeline. We have initiated a risk-based approach to prioritizing the pipeline segments for future smart pig runs or other approved integrity testing methods. This will ensure that the pipelines that have the greatest risk potential receive the highest priority in being scheduled for inspections or pressure tests for integrity.

       We started our smart pigging program in 1988, prior to Department of Transportation (DOT) regulations requiring the program. Beginning in 2002, the DOT required smart pigging or other integrity testing of all DOT-regulated crude oil and refined product pipelines. This requirement is being phased in over a five-year period. Since 1998, we have inspected approximately 98% of the total miles of our pipelines. We anticipate spending approximately $250,000 per year to comply with these new inspection regulations.

       Maintenance facilities containing equipment for pipe repairs, spare parts, and trained response personnel are located along the pipelines. Employees participate in simulated spill deployment exercises on a regular basis. They also participate in actual spill response boom deployment exercises in planned spill scenarios in accordance with Oil Pollution Act of 1990 requirements. We believe that all of our pipelines have been constructed and are maintained in all material respects in accordance with applicable federal, state, and local laws and the regulations and standards prescribed by the American Petroleum Institute, the DOT, and accepted industry practice.

       At our terminals, tanks designed for gasoline storage are equipped with internal or external floating roofs that minimize emissions and prevent potentially flammable vapor accumulation between fluid levels and the roof of the tank. Our terminal facilities have facility response plans, spill prevention and control plans, and other plans and programs to respond to emergencies.

       Many of our terminal loading racks are protected with water deluge systems activated by either heat sensors or an emergency switch. Several of our terminals are also protected by foam systems that are activated in case of fire. All of our terminals are subject to participation in a comprehensive environmental management program to assure compliance with applicable air, solid waste, and wastewater regulations.

Holly Corporation’s Refining Operations

       Although we do not own or operate any refining assets, our pipeline systems are located within Holly Corporation’s refining supply chain. Holly Corporation, through its subsidiaries, is principally a petroleum refiner and marketer. Holly Corporation’s petroleum refining and marketing operations include the manufacturing and marketing of a full range of petroleum

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products, including fuels, lubricants, asphalt, and petrochemicals. The petroleum refining and marketing operations are conducted principally in the West Texas/New Mexico/Arizona area, in Montana and in the Utah/Idaho area. Holly Corporation currently employs approximately 750 people.

       Holly Corporation owns and operates three refineries located in Artesia, New Mexico, Woods Cross, Utah, and Great Falls, Montana.

 
Refineries

       Our pipelines transport light refined products from two of Holly Corporation’s three refineries.

       The Navajo Refinery. The Navajo Refinery has been in continuous operation since Holly Corporation acquired it in 1969. The refinery has been upgraded to one of the most technologically advanced and efficient facilities in the New Mexico/West Texas area. Throughput volumes have increased from 16,000 bpd in 1969 to 75,000 bpd today. The Artesia facility recently underwent an $85 million expansion project that expanded throughput capacity to 75,000 bpd and allows the facility to meet or exceed the federally mandated clean air requirements for gasoline. In addition, Holly Corporation has received permits that will allow it to increase capacity at its Artesia facility to 80,000 bpd without further regulatory approvals.

       The Navajo Refinery has the ability to process a variety of sour (high sulfur) crude oils into high value light refined products, such as gasoline, diesel and jet fuel. For Holly Corporation’s last three fiscal years, sour crude oils have represented more than 80% of the crude oils processed by the Navajo Refinery. The recently completed expansion project allows the Navajo Refinery to now process 100% sour crude oil. The Navajo Refinery’s processing capabilities enable Holly Corporation to vary its crude oil supply mix to take advantage of changes in raw material prices and to respond to fluctuations in the availability of crude oil supplies. For the year ended December 31, 2003, light products represented approximately 90% of all refined products produced at Holly Corporation’s Navajo Refinery. Of the total refined products produced, gasoline represented 57.9%, diesel fuel represented 23.2% and jet fuel represented 8.6% of the Navajo Refinery’s sales volumes by barrel. For the year ended December 31, 2003 and the three months ended March 31, 2004, approximately 99% of the light products produced in the Navajo Refinery were distributed through our pipelines or our terminals.

       Holly Corporation’s Artesia facility is located on a 300-acre site and has fully integrated crude, fluid catalytic cracking, vacuum distillation, alkylation, hydrodesulfurization, isomerization and reforming units, and approximately 1.5 million barrels of feedstock and product tank storage, as well as other supporting units and office buildings at the site. The operating units at the Artesia facility include newly constructed units, older units that have been relocated from other facilities and upgraded and re-erected in Artesia, and units that have been operating as part of the Artesia facility (with periodic major maintenance) for many years, in some cases since before 1970. The Artesia facilities are operated in conjunction with integrated refining facilities located in Lovington, New Mexico, approximately 65 miles east of Artesia. The principal equipment at Lovington consists of a crude unit and an associated vacuum unit. The Lovington facility processes crude oil into intermediate products, which are transported to Artesia by pipeline, and which are then upgraded into finished products at the Artesia facility.

       Holly Corporation distributes light refined products from the Navajo Refinery to its principal markets primarily through our two pipelines from Artesia to El Paso. In addition, Holly Corporation uses our Artesia to Moriarty pipeline and our leased Moriarty to Bloomfield pipeline to transport petroleum products to markets in northwest New Mexico and to Moriarty, New Mexico, near Albuquerque, and to Colorado.

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       Holly Corporation also owns and operates crude oil gathering, transportation and storage assets in West Texas and New Mexico that supply feedstock to the Artesia and Lovington refineries. Holly Corporation purchases crude oil for its Navajo Refinery from producers in nearby Southeastern New Mexico and West Texas. The purchased crude oil is gathered through Holly Corporation’s crude oil gathering systems and tank trucks in New Mexico and Texas and through third party crude oil gathering systems.

       The Woods Cross Refinery. On June 1, 2003, Holly Corporation acquired from ConocoPhillips a petroleum refinery in Woods Cross, Utah (near Salt Lake City), and certain other transportation assets, 25 retail service stations located in Utah and Wyoming, and a 10-year exclusive license to market fuels under the Phillips brand in the states of Utah, Wyoming, Idaho and Montana. Holly Corporation subsequently sold the retail service stations. The Woods Cross Refinery has a current crude oil processing capacity of 25,000 bpd.

       The Woods Cross Refinery currently obtains its supply of crude oil primarily from suppliers in Wyoming and Canada via a common carrier pipeline, which runs from the Canadian border through Wyoming to the refinery. The Woods Cross Refinery’s principal markets include Utah and Idaho where it distributes its products through a network of Phillips 66 branded marketers. The refinery produces primarily gasoline, diesel and jet fuel. We currently terminal refined products for the Woods Cross Refinery in our Spokane, Burley and Boise, Idaho terminals as well as our truck rack and pumpover pipeline facility at Woods Cross.

       The Montana Refinery. The Montana Refinery, in Great Falls, Montana, can process 8,000 bpd of crude oil. The refinery is capable of handling a wide range of crude oils and primarily serves markets in Montana.

       The Montana Refinery currently obtains its supply of crude oil primarily from suppliers in Canada via a common carrier pipeline, which runs from the Canadian border to the refinery. The Montana Refinery’s principal markets include Great Falls, Helena, Bozeman and Billings, Montana. The refinery produces primarily gasoline (including reformulated and premium grades), diesel fuels, jet fuels, and asphalt. The Montana refinery competes principally with three other Montana refiners. We do not currently transport or terminal any of the refined products produced at the Montana Refinery.

       The following table sets forth the input to crude oil processing units (in bpd) for each of Holly Corporation’s refineries during each of Holly Corporation’s last three fiscal years and the three months ended March 31, 2004.

                                   
Three Months
Year Ended Ended
July 31, Year Ended March 31,

December 31,
2001 2002 2003(2) 2004




Input to crude oil processing units (bpd)
                               
 
Navajo Refinery
    57,468       53,640       56,076       67,460  
 
Montana Refinery
    6,166       6,563       6,736       5,890  
 
Woods Cross Refinery(1)
    N/A       N/A       22,540       21,220  


(1)  Based on our ownership from June 1, 2003 to December 31, 2003.
 
(2)  In 2003, Holly Corporation changed its fiscal year end to December 31, 2003.
 
Marketing

       Our pipelines and terminals serve our shippers’ marketing operations in the Southwest and Rocky Mountain regions of the United States as well as northern Mexico. We believe that our

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pipeline and terminalling assets are well-positioned for future growth because many of these assets are located in regions with above average population growth and are associated with Holly Corporation, a significant participant in those regions. We expect that the historical population growth in the Southwest and Rocky Mountain regions of the United States will continue to result in increased demand for refined products and increased throughput for our refined product pipelines and terminals as Holly Corporation’s sales volumes of refined products in those markets continue to grow.

       Refinery Production. The Navajo Refinery converts over 90% of its raw materials throughput into high value light products. Set forth below is certain information regarding the principal products produced by the Navajo Refinery during Holly Corporation’s last three fiscal years and the three months ended March 31, 2004.

                                                                     
Year Ended July 31, Three Months

Year Ended Ended
December 31, March 31,
2001 2002 2003 2004




bpd % bpd % bpd % bpd %








Sales of produced refined products(1)
                                                               
 
Gasolines
    36,000       57.5 %     34,820       58.2 %     36,210       57.9 %     46,943       60.1 %
 
Diesel fuels
    13,810       22.0       12,920       21.6       14,510       23.2       19,639       25.1  
 
Jet fuels
    7,060       11.3       6,570       11.0       5,360       8.5       5,207       6.7  
 
Asphalt
    3,480       5.6       3,450       5.7       4,380       7.0       4,069       5.2  
 
LPG and other
    2,270       3.6       2,070       3.5       2,110       3.4       2,242       2.9  
     
     
     
     
     
     
     
     
 
   
Total
    62,620       100 %     59,830       100 %     62,570       100 %     78,100       100.0 %
     
     
     
     
     
     
     
     
 


(1)  Excludes refined products purchased for resale.

       Light products are shipped by product pipelines or are made available at various points by exchanges with others. Light products are also made ava